EX-13.1 2 a20201231tacex131aif.htm EX-13.1
TRANSALTA CORPORATION
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2020
March 2, 2021

Table of Contents

PRESENTATION OF INFORMATION | 3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS | 3
DOCUMENTS INCORPORATED BY REFERENCE | 4
CORPORATE STRUCTURE | 5
OVERVIEW | 7
GENERAL DEVELOPMENT OF THE BUSINESS | 12
BUSINESS OF TRANSALTA | 19
Hydro Business Segment | 19
Wind and Solar Business Segment | 24
North American Gas Business Segment | 29
Australian Gas Business Segment | 31
Alberta Thermal Business Segment | 33
Centralia Business Segment | 36
Energy Marketing Segment | 37
Corporate Segment | 37
Non-Controlling Interests | 38
PPAs | 39
Competitive Environment | 40
Regulatory Framework | 42
Competitive Strengths | 45
ENVIRONMENTAL RISK MANAGEMENT | 46
Ongoing and Recently Passed Environmental Legislation | 46
TransAlta Activities | 50
RISK FACTORS | 51
EMPLOYEES | 62
CAPITAL AND LOAN STRUCTURE | 63
Common Shares | 63
First Preferred Shares | 63
Credit Facilities | 71
Long-Term Debt | 71
Exchangeable Securities | 72
Non-Recourse Debt | 73
Tax Equity | 73
Restrictions on Debt | 74
CREDIT RATINGS | 74
DIVIDENDS | 76
Common Shares | 76
Preferred Shares | 77
MARKET FOR SECURITIES | 80
Common Shares | 80
Preferred Shares | 81
DIRECTORS AND OFFICERS | 86
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 90
INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS | 90
CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS | 90
MATERIAL CONTRACTS | 91
CONFLICTS OF INTEREST | 91
LEGAL PROCEEDINGS AND REGULATORY ACTIONS | 91
TRANSFER AGENT AND REGISTRAR | 93
INTERESTS OF EXPERTS | 93
ADDITIONAL INFORMATION | 93
AUDIT, FINANCE AND RISK COMMITTEE | 93
AUDIT, FINANCE AND RISK COMMITTEE CHARTER | A- 1
GLOSSARY OF TERMS | B- 1

Presentation of Information
Unless otherwise noted, the information contained in this annual information form ("Annual Information Form" or "AIF") is given as at or for the year ended Dec. 31, 2020. All dollar amounts are in Canadian dollars unless otherwise noted. Unless the context otherwise requires, all references to the "Corporation" and to "TransAlta," "we," "our" and "us" herein refer to TransAlta Corporation and its subsidiaries, including TransAlta Renewables Inc., on a consolidated basis. Reference to "TransAlta Corporation" herein refers to TransAlta Corporation, excluding its subsidiaries. Capitalized terms not defined in the body of this AIF shall have their respective meanings set forth in Appendix "B" – Glossary of Terms hereto.
Special Note Regarding Forward-Looking Statements
This Annual Information Form, including the documents incorporated herein by reference, includes "forward-looking information," within the meaning of applicable Canadian securities laws, and "forward-looking statements," within the meaning of applicable United States securities laws, including the Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may,", "will", "can," "could," "would," "shall," "believe," "expect," "estimate," "anticipate," "intend," "plan," "forecast," "foresee," "potential," "enable," "continue" or other comparable terminology. These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in the forward-looking statements.
In particular, this Annual Information Form (or a document incorporated herein by reference) contains forward-looking statements including, but not limited to: our operating performance and transition to clean power generation, including our goal to have no generation from coal by the end of 2025; the conversion or repowering of our coal-fired units to natural gas and the timing thereof, the amount of capital allocated thereto and the expectations relating to shareholder returns relating to such conversions; the benefits of our Clean Energy Investment Plan, including being a low-cost generator, extending the life of the assets and reducing air emissions and costs; the source of funding for the Clean Energy Investment Plan; our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2020 to 2031 and beyond; potential for growth in renewables and on-site and cogeneration assets, including the timing of commercial operation, and cost, for projects currently under development and construction; the amount of capital allocated to new growth or development projects; our business and anticipated future financial performance and anticipated results, including our outlook and performance targets; our expected success in executing on our growth and development projects; our expectation regarding the anticipated closing date for the sale of TransAlta's interest in the Pioneer Pipeline; the benefits of the Brookfield Investment (as defined below); the timing and completion of growth projects and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the terms of the current or any further proposed share buyback program and the acceptance thereof by the Toronto Stock Exchange ("TSX"), including the timing and number of shares to be repurchased pursuant to any normal course issuer bid; the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, in both the short-term and long-term, and the resulting impact on electricity prices; the impact of load growth, increased capacity and natural gas and other fuel costs on power prices; expectations in respect of generation availability, capacity and production; expectations regarding the role different energy sources, including renewable power generation, will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, including the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; accounting estimates and accounting policies; anticipated growth rates and competition in our markets; our expectations relating to the outcome of existing or potential legal and contractual claims, regulatory investigations and disputes; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms or at all; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; and our credit practices.
The forward-looking statements contained in this Annual Information Form (or a document incorporated herein by reference) are based on many assumptions including, but not limited to, the following material assumptions: impacts arising from COVID-19 not becoming significantly more onerous on the Corporation, which includes the Corporation
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being permitted to continue as an essential service; merchant power prices in Alberta and the Pacific Northwest; our proportionate ownership of TransAlta Renewables not changing materially; no material decline in the dividends expected to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the Alberta energy-only market; and assumptions regarding our current strategy and priorities, including as it pertains to our current priorities relating to our conversions to gas, growing TransAlta Renewables and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets.
Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this AIF (or a document incorporated herein by reference) include, but are not limited to, risks relating to the impact of COVID-19, which cannot currently be predicted, and which present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment and to obtain regulatory approvals on the expected timelines or at all; COVID-19-related force majeure claims; restricted access to capital and increased borrowing costs; a further decrease in short-term and/or long-term electricity demand and lower merchant pricing in Alberta and Mid-C; further reductions in production; increased costs resulting from our efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets; a higher rate of losses on our accounts receivable due to credit defaults; impairments and/or writedowns of assets; and adverse impacts on our information technology systems and our internal control systems, including increased cyber security threats. The forward-looking statements are also subject to other risk factors that include, but are not limited to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; the outcome of pending legal proceedings described in this AIF being adverse to TransAlta; the Brookfield investment being successfully challenged; the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic or market conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather and other climate-change related risks; unexpected increases in cost structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial expectations; natural and man-made disasters resulting in dam failures; the threat of domestic terrorism and cyberattacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner; commodity risk management; industry risk and competition; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta Renewables Inc.; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks; increased costs or delays in the construction or commissioning of pipelines, or sourcing sufficient quantities of natural gas, for the converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables Inc.; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland facility; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" in this Annual Information Form or in a document incorporated herein by reference, including our management's discussion and analysis for the year ended Dec. 31, 2020 (the "Annual MD&A").
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described or might not occur at all. We cannot assure that projected results or events will be achieved.
Documents Incorporated by Reference
TransAlta's audited consolidated financial statements for the year ended Dec. 31, 2020, and related annual management's discussion and analysis are hereby specifically incorporated by reference in this AIF. Copies of these documents are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
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Corporate Structure
Name and Incorporation
TransAlta Corporation is a corporation organized under the Canada Business Corporations Act (the "CBCA"). It was formed by Certificate of Amalgamation issued on Oct. 8, 1992. On Dec. 31, 1992, a Certificate of Amendment was issued in connection with a plan of arrangement involving TransAlta Corporation and TransAlta Utilities Corporation ("TransAlta Utilities" or "TAU") under the CBCA. The plan of arrangement, which was approved by shareholders on Nov. 26, 1992, resulted in common shareholders of TransAlta Utilities exchanging their common shares for shares of TransAlta Corporation on a one-for-one basis. Upon completion of the arrangement, TransAlta Utilities became a wholly owned subsidiary of TransAlta Corporation.
Effective Jan. 1, 2009, TransAlta completed a reorganization, whereby the assets and business affairs of TAU and TransAlta Energy Corporation ("TransAlta Energy" or "TEC") (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a then new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly-owned subsidiary of TransAlta Corporation. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of a partnership agreement and a management services agreement. Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC and Keephills 3 GP Ltd. pursuant to the provisions of the CBCA.
TransAlta amended its articles on Dec. 7, 2010, to create the Series A Shares and Series B Shares; again on Nov. 23, 2011, to create the Series C Shares and Series D Shares; again on Aug. 3, 2012, to create the Series E Shares and Series F Shares; and again on Aug. 13, 2014, to create the Series G Shares and Series H Shares. TransAlta further amended its articles in on Oct. 1, 2020, to create the new series of redeemable, retractable first preferred shares that were issued to an affiliate of Brookfield Renewable Partners ("Brookfield") in October 2020. See "Capital and Loan Structure - Exchangeable Securities".
The registered and head office of TransAlta is located at 110 ‑ 12th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7.
Our Subsidiaries
As at the date of this AIF, the principal subsidiaries of TransAlta Corporation and their respective jurisdictions of formation are set out below.
Certain of our subsidiaries are not wholly owned. The most significant subsidiary is TransAlta Renewables Inc. ("TransAlta Renewables"), which completed its initial public offering in August 2013. In connection with the offering, TransAlta Corporation transferred to TransAlta Renewables certain wind and hydro power generation assets previously held directly or indirectly by TransAlta Corporation. As at Dec. 31, 2020, TransAlta Corporation owned, directly or indirectly, approximately 60 per cent of the outstanding voting equity in TransAlta Renewables. See "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."
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Notes:
(1) Unless otherwise stated, ownership is 100 per cent. As noted elsewhere in this AIF, TransAlta Renewables has economic interests in a number of projects through tracking preferred shares in the capital of TA Energy Inc. and TransAlta Power Ltd., which are both wholly owned by TransAlta Corporation.
(2) We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables, which includes 37.38 per cent through direct ownership and 22.73 per cent through TransAlta Generation Partnership. The remaining approximately 40 per cent interest in TransAlta Renewables is publicly owned.
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Overview
TransAlta
We are one of Canada's largest publicly traded power generators with over 109 years of operating experience. We own, operate and manage highly contracted and geographically diversified portfolio of assets representing a broad range of fuels that include water, wind and solar, natural gas and thermal coal. We are currently undertaking a multi-year transition to convert or retire all of our thermal coal units completely by the end of 2025. This transition will see our thermal units in Alberta discontinue all firing with thermal coal and the discontinuation of all coal mining operations by the end of Dec. 31, 2021. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill. Consistent with our commitment under this bill, Centralia Unit 1 retired on Dec. 31, 2020 and the remaining unit is set to retire on Dec. 31, 2025. Our energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions.
Our vision is to be a leader in clean electricity and we are committed to a sustainable future. Our mission is to provide safe, low-cost and reliable clean electricity. With our 109-year history of powering economies and communities, we apply our expertise, scale and diversified fuel mix to capitalize on opportunities in our core markets and grow in areas where our competitive advantages can be employed.
Our values are grounded in safety, innovation, sustainability, respect and integrity, all of which enable us to work towards our common goals. These values are the principles that define our corporate culture. They reflect our skills and mindset, while providing a framework for everything we do, guiding both internal conduct and external relationships. These values are at the heart of our success.
•Safety – Ensure the health and safety of our people, partners and stakeholders
•Innovation – Develop and embrace innovative solutions to challenges
•Sustainability – Reduce the impact of resource use in everything we do
•Respect – Support our people, our partners, our communities and our environment
•Integrity – Focus on honesty, transparency and doing what's right
TransAlta and its predecessors have been engaged in the development, production and sale of electric energy since 1911. We are among Canada's largest non-regulated electricity generation and energy marketing companies with a total of 8,128 megawatts ("MW") of net maximum capacity. We are focused on generating and marketing electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by hydro, wind, solar, energy storage, natural gas and thermal coal.
TransAlta's diversified portfolio of power generating assets across multiple geographies, technologies and mix of merchant and contracted assets provides cash flows that support our ability to pay dividends to our shareholders, reinvest in growth and fund sustaining and capital expenditures.
Corporate Strategy
Our strategic focus is to invest in a disciplined manner in a range of clean and renewable power generation such as hydro, wind, solar, energy storage and thermal (natural- gas fired and cogeneration) and develop customer-centric green power solutions that produce electricity for the needs of our industrial customers and communities in order to deliver returns to our shareholders.
TransAlta's Clean Energy Investment Plan, announced in 2019, includes converting our existing Alberta coal assets to natural gas and advancing our leadership position in on-site generation and renewable electricity. The Clean Energy Investment Plan identified opportunities of $1.9 billion to $2.1 billion that TransAlta is pursuing. A significant number of these opportunities have been completed with the projects achieving commissioned status in 2019 and 2020.
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The following provides an overview of our Clean Energy Investment Plan:
1. Successfully convert to natural gas as the primary fuel source in the Alberta thermal fleet
We are transitioning our Alberta thermal fleet to natural gas as part of our Clean Energy Investment Plan. We plan to invest between $900 million to $1.0 billion to convert or repower our Alberta thermal fleet to natural gas. This will repurpose and reposition our fleet to a cleaner, gas-fired fleet while delivering attractive returns by leveraging the Corporation's existing infrastructure.
The highlights of these gas conversion investments include:
•Positioning TransAlta’s fleet as a low-cost clean energy generator in the Alberta energy-only market;
•Generating attractive returns by leveraging the Corporation’s existing infrastructure;
•Significantly extending the life and cash flows of our Alberta thermal assets; and
•Significantly reducing air emissions and costs.
2. Deliver growth in our renewables fleet
We expanded our renewables platform in the U.S. in 2020 and continue to identify additional opportunities with customers on electricity offerings with a higher component of power coming from renewable sources. Our focus is to deliver solid returns using exceptional project development, construction and integration of skills and capabilities.
3. Expand presence in the U.S. renewables market
A major focus of our business development efforts is on the renewables segment of the U.S. market. Demand for new renewables in the U.S. is expected to continue its strong growth in the near term and President Biden is expected to initiate policies designed to support further renewables growth. We have started prospecting for new renewable development sites in a number of attractive U.S. markets. These opportunities are expected to grow TransAlta Renewables, use its excess debt capacity and deliver stable dividends back to TransAlta.
4. Advance and expand our on-site generation and cogeneration business
We are focused on growing our on-site and cogeneration asset base, a business segment we have deep experience in, having provided on-site cogeneration services to customers since the early 1990s. Our current pipeline under evaluation is approximately 600 MW and our technical design, operations experience and safety culture make us a strong partner in this segment. We see this segment growing as industrial and large-scale customers are looking to find solutions to help lower the costs of power production, replace aging or inefficient equipment, reduce network costs and meet their environmental,social, and governance objectives.
5. Maintain a strong financial position
We intend to remain disciplined in our capital investment strategy and continue to build on our already strong financial position. The Clean Energy Investment Plan is being funded from the cash raised through the strategic investment by Brookfield, cash generated from operations and capital raised through TransAlta Renewables.
Our Economic, Environmental, Social and Governance Leadership (E 2 SG)
Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental impacts and societal and community needs. We refer to this as E 2 SG. As we execute our strategy, our decisions are governed with a view to also deliver on our E 2 SG objectives. We have a long history of adopting leading-sustainability practices, including over 25 years of sustainability reporting and voluntarily integrating our sustainability report into our annual report. We have been issuing an integrated annual report since 2015. We test our practices and our reporting against standards set by CDP (formerly the Carbon Disclosure Project), the Task Force on Climate-related Financial Disclosures and the Canadian Council for Aboriginal Business.
Our key strategic sustainability pillars build on our corporate strategy and weave through our business. Some of these focus areas are already part of our DNA, and our track record in these areas illustrate our commitment to sustainability (including climate change leadership and safety). In other areas where we have set new goals in recent years (including, Diversity, Equity and Inclusion), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:
1.Clean, Reliable and Sustainable Electricity Production
2.Safe, Healthy, Diverse, and Engaged Workplace
3.Positive Indigenous, Stakeholder and Customer Relationships
4.Progressive Environmental Stewardship
5.Technology and Innovation
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In 1990, we were the first Canadian company to purchase carbon offsets and in 2000 we were an early adopter of wind power generation. Through our ongoing transformational efforts, to date we have reduced our total greenhouse gas emissions by over 60 per cent, or over 25 million tonnes, since 2005. Our goal is to have no generation fuelled by coal by the end of 2025. The Corporation aligns its E 2 SG targets with the UN Sustainable Development Goals.
The key components of our Corporation's approved 2020 E 2 SG targets include:
•a continued focus on safe operations and environmentally sustainable practices, including undertaking significant reclamation work;
•by 2026, achieving a 95 per cent reduction in sulphur dioxide emissions and an 80 per cent reduction of nitrogen oxide ("NOx") emissions over 2005 levels from our coal facilities, and by 2030 a company-wide reduction in GHG emissions of 60 per cent below 2015 levels;
•undertaking initiatives that will enhance the environmental performance of the Corporation, including converting coal facilities to natural gas and developing new renewable projects that support customer E 2 SG goals to achieve both long-term power price affordability and carbon reductions;
•supporting equal access to all levels of education for youth and Indigenous peoples through financial assistance and employment opportunities;
•enhancing our commitment to workplace gender diversity, including adopting a target of 50 per cent representation of women on the Board by 2030 and at least 40 per cent representation of women among all of our employees by 2030; and
•maintaining our commitment to leading E 2 SG disclosures.
Our Capital Allocation and Financing Strategy
Our goal is to remain disciplined with our capital investment program and ensure that we continue to enhance our financial position. We are focused on strengthening our financial position and cash flow coverage ratios to ensure that a strong balance sheet is maintained and sufficient capital is available to execute our strategy.
Our goal is to return our deconsolidated debt levels to below a 3.0x debt-to-EBITDA ratio and to continue to pay and grow our dividend. We have adopted a debt-to-EBITDA target range of between 2.5x to 3.0x, based on TransAlta's deconsolidated comparable EBITDA.
We have also committed to a capital allocation program that provides investors with a line of sight on how we would consider changes into the future and provide further transparency on how the dividends that we receive from our ownership in TransAlta Renewables are either being returned to shareholders or reinvested at TransAlta. The Board has set a target of returning between 10 per cent and 15 per cent of TransAlta deconsolidated funds from operations to common shareholders.
We are confident that the above program balances the demands associated with meeting our goals around reinvestment, new growth and debt repayments along with providing shareholders a return on their capital.
Our Business Segments
The Hydro segment has a net ownership interest of approximately 926 MW of owned electrical-generating capacity. The facilities within this segment are predominantly located in Alberta, British Columbia, and Ontario.
The Wind and Solar segment has a net ownership interest of approximately 1,544 MW of owned electrical-generating capacity and includes facilities located in Alberta, Ontario, New Brunswick and Québec, and the states of Massachusetts, Minnesota, New Hampshire, Pennsylvania, Washington and Wyoming.
The North American Gas segment has a net ownership interest of approximately 866 MW of owned electrical-generating capacity and includes facilities located in Alberta, Ontario and Michigan.
The Australian Gas segment has a net ownership interest of approximately 450 MW of owned electrical-generating capacity and a pipeline located in Western Australia.
The Alberta Thermal segment has a net ownership interest of approximately 2,666 MW of owned electrical-generating capacity as well as our interest in the Pioneer Pipeline. Sundance Unit 6 underwent a simple boiler conversion in the fourth quarter of 2020 and the future conversions to gas and repowerings will remain in this segment.
The Centralia segment holds our Centralia thermal facility, which, as of Dec. 31, 2020, represented a net ownership interest of 1,340 MW of owned electrical-generating capacity. One of the units, which represents half of the facility's generating capacity, was retired on Dec. 31, 2020. From 2021 to 2025, the remaining unit has a capacity of 670 MW. The Centralia facility is located in the state of Washington.
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The Energy Marketing segment is responsible for marketing our production through short-term and long-term contracts, for securing cost-effective and reliable fuel supply, and for maximizing margins by optimizing our assets as market conditions change. Our Energy Marketing segment is actively engaged in the trading of power, natural gas and environmental products across a variety of markets.
The Corporate segment supports each of the above segments and includes the Corporation's central finance, legal, administrative, business development and investor relation functions.
We regularly review our operations in order to optimize our generating assets and evaluate appropriate growth opportunities to maximize value to the Corporation. We have in the past made, and may in the future make, changes and additions to our fleet of hydro, wind, solar, energy storage, natural gas and thermal coal.
TransAlta Renewables
TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 60 per cent direct and indirect ownership interest as of the date of this Annual Information Form. TransAlta Renewables is one of the largest generators of wind power and among the largest publicly traded renewable power generation companies in Canada.
TransAlta Renewables was formed in 2013 to realize specific strategic and financial benefits, including: (a) establishing a focused vehicle for pursuing and funding growth opportunities in the renewable power and gas generation sector; (b) unlocking the value of TransAlta’s renewable asset platform; (c) retaining TransAlta’s majority ownership and operatorship of the underlying assets; (d) providing proceeds of approximately $200-$250 million to repay debt and support TransAlta’s balance sheet; and (e) creating additional financial flexibility for TransAlta by providing another source of capital with a separate cost of capital.
We continue to realize the benefit of having assets with different risk/return profiles in two separate entities as it enables each company to secure appropriate financing and investors. TransAlta holds mainly merchant assets in hydro and natural gas while TransAlta Renewables holds assets primarily with long-term contracts generating stable cash flows in wind, solar, natural gas and energy storage. TransAlta’s majority ownership of TransAlta Renewables has supported the Corporation in implementing its overall strategy of developing, constructing or acquiring additional renewable assets.
TransAlta Renewables, or one or more of its wholly-owned subsidiaries, directly own certain of our wind, hydro, natural gas and energy storage facilities. TransAlta Renewables also owns economic interests in a number of our other facilities. TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management and Operational Services Agreement and the Governance and Cooperation Agreement between TransAlta Corporation and TransAlta Renewables. See "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."
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TransAlta's Map of Operations
The following map outlines TransAlta's operations as of Dec. 31, 2020.
Note:
(1) Includes facilities directly owned by TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables.
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General Development of the Business
Significant regulatory changes continue to have extensive impacts on the Corporation's business and strategy. In 2015, the Government of Alberta announced the Alberta Climate Leadership Plan that set goals to reduce carbon emissions and phase out pollution from coal-generated electricity by 2030. TransAlta responded quickly to this announcement and set down the path to fully transform itself into a leading clean electricity company. Part of this strategy is to fully convert our existing coal fleet in Canada to natural gas. This will eliminate thermal coal as a fuel source on our operating units by the end of 2021 in Canada. In addition, we continue to expand our renewable generation and cogeneration fleet with numerous wind and gas projects currently under development. Throughout this transformation, we always keep our mission statement in mind: to provide safe, low-cost and reliable clean electricity.
The significant events and conditions affecting our business during the three most recently completed financial years, and during the current year to date, are summarized below. Certain of these events and conditions are discussed in greater detail under the heading "Business of TransAlta."
Three-Year History
Generation and Business Development
2021
TransAlta Completes First Off-Coal Conversion and Achieves Major Milestone in Phase-Out of Coal
On Feb. 1, 2021, the Corporation announced that it had completed the first of three planned boiler conversions to gas at the Sundance and Keephills power generation facilities near Wabamun, Alberta. The full conversion of Sundance Unit 6 from thermal coal to natural gas allows the unit to reduce its carbon dioxide emissions by half from approximately 1.05 tonnes carbon dioxide equivalent ("CO 2 e") per megawatt hour ("MWh") to approximately 0.52 tonnes of CO 2 e per MWh.
TransAlta's Alberta Power Purchase Arrangements Expire
On Dec. 31, 2020, the Alberta Power Purchase Arrangements for many of our Alberta hydro facilities and Keephills 1 and 2 units expired and, commencing Jan. 1, 2021, these facilities began operating on a merchant basis in the Alberta market. The facilities are now dispatched to benefit from the price volatility in the Alberta energy-only electricity market and to provide ancillary services. As such, they form part of our Alberta electricity portfolio optimization activities. The variability in production by facility is driven by the diversity in our fuel types which enables portfolio management. The Alberta portfolio of production includes hydro, wind, energy storage and thermal units. A portion of the base load of the portfolio is hedged to provide cash flow certainty.
2020
TransAlta Sells 303 MW Portfolio Including 274 MW of Wind to TransAlta Renewables
On Dec. 23, 2020, the Corporation and TransAlta Renewables entered into definitive agreements for the acquisition of three assets consisting of: (a) a 100 per cent direct interest in the 207 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta; (b) a 49 per cent economic interest in the 137 MW Skookumchuck wind facility in operation located across Thurston and Lewis counties in Washington State; and (c) a 100 per cent economic interest in the 29 MW Ada facility in operation located in Ada, Michigan. The total acquisition price for the portfolio was $439 million and includes the remaining construction costs for the Windrise wind project. The transaction will close in separate tranches early in 2021 subject to the satisfaction of certain closing condition; however, the economic benefit of the transaction will be effective as at Jan. 1, 2020. The sale of the Windrise wind project to TransAlta Renewables closed on Feb. 26, 2021. TransAlta Renewables will fund the cash consideration and remaining construction costs with the proceeds from the South Hedland financing.
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TransAlta Acquired 30 per cent Equity Interest in EMG International LLC ("EMG")
On Nov. 30, 2020, the Corporation acquired a 30 per cent equity investment in EMG. The Corporation and EMG have joined forces to leverage their complementary customer bases to grow each business and further enhance product offerings to help customers reach their sustainability goals. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. TransAlta’s investment in EMG provides a low-risk entry point into the wastewater treatment industry and creates strong synergies with the Corporation's existing customer service offerings.
Skookumchuck Wind Project Equity Investment
On Nov. 25, 2020, the Corporation closed its 49 per cent equity investment in the Skookumchuck wind project ("Skookumchuck") with Southern Power Company, a subsidiary of Southern Company. Skookumchuck is a 137 MW wind project located in Lewis and Thurston counties, Washington consisting of 38 Vestas V136 wind turbines. Skookumchuck began commercial operation on Nov. 7, 2020 and has a 20-year power purchase agreement (PPA) with Puget Sound Energy. The economic interest in this facility is being sold to TransAlta Renewables in the first half of 2021.
TransAlta Fast- Tracks Off Coal and Highvale Mine to Discontinue Mining by End of 2021
On Nov. 4, 2020, the Corporation announced that it would discontinue all mining operations at its Highvale mine by Dec. 31, 2021. Effective Jan. 1, 2022, TransAlta will cease coal-fired generation in Canada. TransAlta’s Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas, resulting in the maximum capability of these units being reduced to 70 MW and 113 MW, respectively, effective Jan. 1, 2022. The Corporation continues to evaluate these units as candidates for boiler conversions or full repowering based on market fundamentals.
BHP Nickel West 15-Year Contract Extension
On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Corporation, replaced and extended its current PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia.
The new agreement was effective Dec. 1, 2020 and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross facilities for BHP's mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiatives under the extended PPA with SCE are underway, including a 18.5 MW solar photovoltaic project supported by a battery energy storage system and a waste heat steam turbine system.
TransAlta Renewables Announced Commercial Operation of WindCharger, Alberta's First Utility-Scale Battery Storage Project
On Oct. 15, 2020, the WindCharger battery storage project began commercial operation. WindCharger is Alberta’s first utility-scale, lithium-ion energy storage project and it uses Tesla Megapack technology. TransAlta is expected to receive co-funding of almost 50 per cent of the $14 million construction cost from Emissions Reduction Alberta. The 10 MW / 20 MWh battery storage facility was acquired by TransAlta Renewables from the Corporation on Aug. 1, 2020. The Corporation also executed a 20-year battery storage usage contract with TransAlta Renewables in which the Corporation pays a fixed monthly capacity charge for the exclusive right to operate and dispatch the battery in the Alberta market. WindCharger is participating in both the Alberta wholesale energy and Ancillary Services market of the AESO.
TransAlta and Tidewater Midstream ("Tidewater") Enter into an Agreement to Sell the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”)
On Oct. 1, 2020, TransAlta announced that it had entered into a definitive Purchase and Sale Agreement providing for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO. The aggregate purchase price of $255 million represents both TransAlta's and Tidewater's interests. This agreement replaces the previous Purchase and Sale Agreement to sell the Pioneer Pipeline to NOVA Gas Transmission Ltd. ("NGTL"). Following the closing of the transaction, the Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations.
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Retirement of Sundance 3 Coal-Fired Thermal Facility
On July 22, 2020, the Corporation announced that it gave notice to the Alberta Electric System Operator ("AESO") to retire Sundance Unit 3 effective July 31, 2020. The retirement decision was largely driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta.
Acquisition of Contracted Cogeneration Asset in Michigan
On May 19, 2020, we closed the acquisition of a contracted cogeneration asset from two private companies for a purchase price of US$27 million. The asset is a 29 MW cogeneration facility ("Ada") in Michigan which is contracted under a long-term PPA and steam sale agreement for approximately six years with Consumers Energy and Amway. Ada has been included in the North American Gas segment results, which was previously known as the Canadian Gas segment. The economic interest in this facility is being sold to TransAlta Renewables in the first half of 2021.
2019
TransAlta Renewables Inc. Delivers on Two Contracted US Wind Projects
The Big Level wind facility and the Antrim wind facility began commercial operation on Dec. 19, 2019, and Dec. 24, 2019, respectively. TransAlta Renewables has an economic interest in these two US wind facilities. The 90 MW Big Level wind facility located in Pennsylvania is under a 15-year contract with Microsoft and the 29 MW Antrim wind facility located in New Hampshire is under two 20-year contracts with Partners Healthcare and New Hampshire Electric Co-op, respectively. All counterparties have a Standard & Poor’s credit rating of A+ or better.
During the third quarter of 2019, subsidiaries of TransAlta entered into final agreements with an external party for a planned tax equity investment in the Antrim and Big Level wind facilities. In December 2019, following Antrim and Big Level each achieving commercial operation, approximately $166 million (US$126 million) of tax equity proceeds were raised by the TransAlta project entities to partially fund the Antrim and Big Level wind facilities, for US$41 million and US$85 million, respectively.
TransAlta Renewables, through its economic interest ownership, provided construction funding with a combination of tracking preferred shares and interest-bearing notes issued by the project entity. The tax equity proceeds were used to repay TransAlta Renewables the principal and accrued interest outstanding on the interest-bearing promissory notes utilized to fund the construction.
Advancing our Clean Energy Investment Plan
In 2019, we announced our Clean Energy Investment Plan, which included plans to convert our existing Alberta coal assets to natural gas and advance our leadership position in on-site generation and renewable energy. TransAlta’s initial plan included converting three of its existing Alberta thermal units to gas in 2020 and 2021 by replacing existing coal burners with natural gas burners. The cost to convert is estimated to be approximately $35 million per unit.
On Oct. 30, 2019, we acquired two 230 MW Siemens F-class gas turbines and related equipment for $84 million from Kineticor Holdings Limited Partnership #2 ("Kineticor") and pertaining to their Three Creeks project. These turbines will be redeployed to our Sundance site as part of the strategy to repower Sundance Unit 5 to a highly efficient combined-cycle unit, with an expected commercial operation date in 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $800 million to $825 million, well below a greenfield combined-cycle project.
Kaybob Generation Project
In 2019, TransAlta and Energy Transfer Canada ("ET Canada", formerly known as SemCAMS Midstream ULC) entered into agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant (“K3”). The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sept. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada.
Agreement to Swap Non-Operating Interests in Keephills 3 and Genesee 3
On Aug. 2, 2019, we entered into definitive agreements with Capital Power Corporation (“Capital Power”) providing for the swap of our respective non-operating interests in the Keephills 3 facility and the Genesee 3 facility. On Oct. 1, 2019, we closed the transaction with Capital Power. As a result, we own 100 per cent of the Keephills 3 facility and Capital Power owns 100 per cent of the Genesee 3 facility.
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Strategic Investment by Brookfield Renewable Partners
On March 25, 2019, we announced a strategic investment by Brookfield that crystallizes the future value of our Hydro Assets, enhances our financial position to execute our strategy, accelerates the opportunity to return capital to shareholders, and provides TransAlta with a partner who has world-class expertise in renewable power platforms and hydroelectric generation . This investment ensures TransAlta will transition to 100 per cent clean electricity by the end of 2025.
Under the terms of an investment agreement (the "Investment Agreement"), Brookfield agreed to invest $750 million in TransAlta through the purchase of exchangeable securities (described below), which are exchangeable by Brookfield into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA. In addition, subject to the exceptions in the Investment Agreement, Brookfield has committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to 9 per cent. On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for 7 per cent unsecured subordinated debentures due May 1, 2039. The further $400-million investment tranche closed on Oct. 30, 2020 in exchange for a new series of redeemable, retractable first preferred shares.
Benefits of the investment are highlighted below:
•includes a significant $750 million capital injection that is being used to advance our gas conversion transition strategy, advance the development of existing and new growth projects and for general corporate purposes;
•recognizes the future anticipated value of our Hydro Assets;
•creates a long-term cornerstone shareholder;
•strengthens our operating capabilities;
•accelerates the return of capital to shareholders through share buy backs; and
•adds extensive renewables experience and expertise by electing two experienced Brookfield directors to our Board of Directors.
Extended Mothballing of Sundance Unit 3 and Unit 5
On March 8, 2019, we announced that the AESO granted the extension of the mothballing for the Sundance Units described below:
•Sundance Unit 3 until Nov. 1, 2021, extended from the previous date of April 1, 2020; and
•Sundance Unit 5 will remain mothballed until Nov. 1, 2021, extended from the previous date of April 1, 2020.
The extensions were requested by us based on the Corporation's assessment of market prices and market conditions Subsequently, on July 31, 2020, we retired Sundance Unit 3.
2018
Pioneer Pipeline
On Dec. 17, 2018, we exercised our option to acquire 50 per cent ownership in the Pioneer Pipeline. During the second quarter of 2019, the Pioneer Pipeline transported its first gas four months ahead of schedule to our generating units at Sundance and Keephills. The sale of the Pioneer Pipeline by TransAlta and Tidewater to ATCO is expected to close in the second quarter of 2021.
Alberta Renewable Energy Program Project – Windrise
On Dec. 17, 2018, our 207 MW Windrise wind project was selected by the AESO as one of the three selected projects in the third round of its Renewable Electricity Program. TransAlta and the AESO executed a Renewable Electricity Support Agreement with a 20-year term. The Windrise project is situated on 11,000 acres of land located in the county of Willow Creek, Alberta.
TransAlta Renewables' New Brunswick Wind Power Expansion Complete
On Oct. 19, 2018, TransAlta Renewables announced that the 17.25 MW expansion of the wind facility at Kent Hills, in New Brunswick, reached commercial operation, bringing total generating capacity to 167 MW. Under the 17-year PPA, New Brunswick Power receives both energy to the province's electricity grid and renewable energy credits ("RECs"). The Kent Hills 3 expansion is located on approximately 20 acres of Crown land and consists of five Vestas V126 turbines. Natural Forces Technologies Inc., a wind-energy developer based in Atlantic Canada, co-developed and co-owns the wind facility with TransAlta Renewables.
Retirement of Sundance Unit 1 and Unit 2 and Mothball Schedule Update
Effective July 31, 2018, we retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size, and the capital requirements needed to return the unit to service. In addition to the retirement of Sundance Unit 2 our mothball
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outage schedule had been updated to provide that Sundance Unit 5 will continue to be mothballed up to Nov. 1, 2021 (extended from the previous date of April 1, 2020).
Sale of Three Renewable Assets
On May 31, 2018, TransAlta Renewables acquired from us an economic interest in the 50 MW Lakeswind wind facility in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, TransAlta Renewables acquired ownership of the 20 MW Kent Breeze wind facility located in Ontario. The total purchase price payable for the three assets, which had an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt. TransAlta Renewables funded the equity portion of the acquisitions using its existing liquidity. On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million (US$25 million) of tracking preferred shares of a subsidiary of TransAlta, to fund the repayment of Mass Solar's project debt.
Acquisition of US Wind Projects
On Feb. 20, 2018, TransAlta Renewables entered into an arrangement to acquire economic interests in the Big Level and Antrim wind facilities. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provide TransAlta Renewables with an economic interest in the Big Level and Antrim wind facilities. The Big Level and Antrim wind facilities began commercial operation on Dec. 19, 2019, and Dec. 24, 2019, respectively. See "- 2020 - TransAlta Renewables Inc. Delivers on Two Contracted US Wind Projects."
Corporate and Energy Marketing
2021
Management and Board of Directors Changes
On Feb. 4, 2021, TransAlta announced that John Kousinioris will succeed Dawn Farrell as President and Chief Executive Officer and will join the Board of TransAlta on April 1, 2021. As part of the transition, Mr. Kousinioris stepped down as President and as a member of the Board of Directors of TransAlta Renewables. effective Feb. 5, 2021. Todd Stack assumed the role of President of TransAlta Renewables, and also joined the Board of TransAlta Renewables effective Feb. 6, 2021. Mr. Stack continues as TransAlta's Executive Vice President, Finance & Trading and Chief Financial Officer. During the first quarter of 2021, Brett Gellner, our Chief Development Officer, announced he will retire effective April 30, 2021. Mr. Gellner will remain on the TransAlta Renewables' Board of Directors.
2020
Declaration of a 6% Common Share Dividend Increase
On Dec. 23, 2020, the Corporation announced a 6 per cent increase on its common share dividend for the quarter ending March 31, 2021. The quarterly dividend of $0.045 per common share represents an annualized dividend of $0.18 per common share, an increase of $0.01 per common share.
TransAlta Receives an A- Industry Leader Score from CDP
On Dec. 14, 2020, the Corporation announced that CDP (the global disclosure system for environmental impacts formerly known as the Climate Disclosure Project) recognized TransAlta with an A- score, ranking the Corporation among industry leaders on climate change management.
Redemption of Medium-Term Notes
On Nov. 25, 2020, the Corporation redeemed all of its outstanding and due 5.0 per cent Senior Unsecured Medium-Term Notes, in the aggregate principal amount of $400-million. The redemption was funded with cash-on-hand.
Diversity and Inclusion Pledge
On Nov. 4, 2020, the Corporation announced that the Board has adopted a Diversity and Inclusion Pledge that commits the Corporation to advancing diversity and inclusion in the workplace. By committing to this pledge, the Corporation will seek to remove systemic barriers that may prevent diverse employees from thriving, including visible minorities, Indigenous people, members of the LGBTQ+ community, persons with disabilities, and women. The persistent inequities around the world underscore the urgent need to address and alleviate racial, ethnic, and other tensions, to remove barriers that perpetuate these inequalities and to promote an inclusive working environment for all employees. TransAlta firmly believes that true diversity is good for the economy, it improves corporate performance, drives growth, and enhances employee engagement. The Diversity and Inclusion Pledge acknowledges these challenges and seeks to: (a) encourage conversations about diversity and inclusion within the workplace; (b) expand education regarding
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diversity, equality and inclusion; (c) create best practices that result in the establishment of programs and initiatives relating to diversity and inclusion within the workplace; and (d) drive accountability by regularly reporting and evaluating the success of the Corporation’s programs and initiatives.
TEC Hedland Pty Ltd. ("TEC") Secures AU$800 Million Financing
On Oct. 22, 2020 TEC, a subsidiary of the Corporation, closed an AU$800-million senior secured note offering ("Offering"), by way of a private placement, which is secured by, among other things, a first-ranking charge over all assets of TEC. The Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042 with principal payments starting on March 31, 2022. The Offering has a rating of BBB from Kroll Bond Rating Agency.
TransAlta Renewables received $480 million (AU$515 million) of the proceeds from the Offering through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd., which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022. The remaining proceeds from the Offering were set aside for required reserves and transaction costs.
TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the Windrise wind project and expects to use the remaining proceeds to acquire the economic interests in the Skookumchuck wind facility and the Ada facility.
Normal Course Issuer Bid
On May 26, 2020, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement a Normal Course Issuer Bid ("NCIB") for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its public float of common shares as at May 25, 2020. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.
TransAlta Declares Increased Common Dividend
On Jan. 16, 2020, we declared an increase in the annualized dividend to $0.17 per common share, representing a 6.25 per cent increase over the prior dividend level.
TransAlta Appoints John P. Dielwart as the Chair of the Board
On Jan. 16, 2020, we announced that John P. Dielwart will be appointed Chair of the Board effective immediately following the retirement of Ambassador Gordon D. Giffin at the 2020 annual meeting of shareholders. Mr. Dielwart became Chair effective April 21, 2020.
2019
Favourable Conclusion Regarding the Sundance B and C PPAs Termination Payment
On Aug. 26, 2019, we announced that we were successful in our arbitration with the Balancing Pool for the remaining payment related to the termination of the Sundance B and C PPA. As a result of the arbitration decision, we received the full amount we had been seeking to recover, being equal to $56 million, plus GST and interest from the Balancing Pool. This payment related to TransAlta’s historical investments in certain mining and corporate assets that the we believed should have been included in the net book value calculation of the PPAs that had been disputed by the Balancing Pool.
Appointment of Chief Financial Officer
On May 16, 2019, we appointed Todd Stack as our Chief Financial Officer. Mr. Stack previously served as Managing Director and Corporate Controller of the Corporation and was responsible for providing leadership and direction over TransAlta’s financial activities, corporate accounting and reporting, tax, and corporate planning.
2018
Redemption of Medium-Term Notes
On Aug. 2, 2018, we redeemed all of our then outstanding 6.40 per cent Medium-Term Notes, due Nov. 18, 2019, in the aggregate principal amount of $400 million. The redemption price for these notes was $1,061.736 per $1,000 principal amount of the notes (representing, in aggregate, $425 million) including a prepayment premium and accrued and unpaid interest on the Notes to the redemption date.
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$345 Million Bond Offering
On July 20, 2018, our indirect wholly-owned subsidiary, TransAlta OCP LP, issued approximately $345 million of bonds, sold by way of a private placement, which are secured by, among other things, a first-ranking charge over all but a nominal percentage of the equity interests in TransAlta OCP and its general partner, and a first-ranking charge over all of TransAlta OCP's accounts and certain other assets. The amortizing bonds bear interest from their date of issue at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.
TransAlta Renewables Completes $150- Million Bought Deal Offering of Common Shares
On June 22, 2018, TransAlta Renewables issued, pursuant to an underwritten offering on a bought deal basis, 11,860,000 common shares in the capital of TransAlta Renewables at a price of $12.65 per share for gross proceeds to TransAlta Renewables of approximately $150 million. As a result of the offering, our interest in TransAlta Renewables was reduced from approximately 64 per cent to 61 per cent.
Redemption of Senior Notes
On March 15, 2018, we redeemed all of our then outstanding US$500 million 6.65 per cent senior notes maturing May 15, 2018. The redemption price for the notes was approximately $617 million, including a $5-million early redemption premium and accrued and unpaid interest on the notes to the redemption date.
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Business of TransAlta
Our Hydro, Wind and Solar North American Gas and Australian Gas, Alberta Thermal, and Centralia business segments are responsible for operating and maintaining our electrical generation facilities as well as the related mining operations in Canada and the US. Our Energy Marketing segment is responsible for marketing our production, securing cost-effective and reliable fuel supply and deploying our competitive knowledge of power, transmission, environmental products and gas markets to capitalize on short-term arbitrage opportunities across various geographic regions aided by market and price volatility without materially changing the risk profile of the Corporation. All the segments are supported by a Corporate segment.
As the Corporation transforms into a leading clean electricity company, it is expected that the proportion of revenue attributable to the Alberta Thermal and Centralia business units will decline relative to the other business units. In addition, the Corporation continues to transition to a leaner organization through continuous optimization with a reduced cost structure to support the new business model.
The following table identifies each revenue-generating business segment's contribution to revenues as at Dec. 31, 2020:

| 2020 Revenues(1) | 2019 Revenues(1)
Alberta Thermal | 29% | 35%
Centralia | 24% | 24%
North American Gas | 10% | 9%
Australian Gas | 8% | 7%
Wind and Solar | 16% | 13%
Hydro | 7% | 7%
Energy Marketing | 6% | 5%

Note:
(1) Includes 100 per cent of the revenue of TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables.
For further information on our segment earnings and assets, please refer to Note 5 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. See "Documents Incorporated by Reference" in this AIF.
The following sections of this AIF provide detailed information on facilities by geographic location and fuel type.
Hydro Business Segment
The Hydro business segment holds an interest in 926 net MWs. The facilities are located in British Columbia, Alberta, Ontario and Washington State.
As well as contracting for power, we enter into long-term and short-term contracts to sell the environmental attributes from the merchant hydro facilities. These activities help to ensure earnings stability from these assets. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.
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The following table summarizes our hydroelectric facilities as at Dec. 31, 2020:

Facility Name | Province/ State | Ownership (%) | Net Capacity Ownership Interest (MW)(1) | Commercial Operation Date | Revenue Source | Contract Expiry Date(2)
Alberta - Bow River System |  |  |  |  |  |
Barrier(3) | AB | 100 | 13 | 1947 | Alberta PPA | 2020
Bearspaw(3) | AB | 100 | 17 | 1954 | Alberta PPA | 2020
Cascade(3) | AB | 100 | 36 | 1942, 1957 | Alberta PPA | 2020
Ghost(3) | AB | 100 | 54 | 1929, 1954 | Alberta PPA | 2020
Horseshoe(3) | AB | 100 | 14 | 1911 | Alberta PPA | 2020
Interlakes(3) | AB | 100 | 5 | 1955 | Alberta PPA | 2020
Kananaskis(3) | AB | 100 | 19 | 1913, 1951 | Alberta PPA | 2020
Pocaterra | AB | 100 | 15 | 1955 | Merchant | ‑
Rundle(3) | AB | 100 | 50 | 1951, 1960 | Alberta PPA | 2020
Spray(3) | AB | 100 | 112 | 1951, 1960 | Alberta PPA | 2020
Three Sisters(3) | AB | 100 | 3 | 1951 | Alberta PPA | 2020
Alberta - Oldman River System |  |  |  |  |  |
Belly River (4) (5) | AB | 100 | 3 | 1991 | Merchant | ‑
St. Mary (4) (5) | AB | 100 | 2 | 1992 | Merchant | ‑
Taylor (4) (5) | AB | 100 | 13 | 2000 | Merchant | ‑
Waterton (4) (5) | AB | 100 | 3 | 1992 | Merchant | ‑
Alberta - North Saskatchewan River System |  |  |  |  |
Bighorn(3) | AB | 100 | 120 | 1972 | Alberta PPA | 2020
Brazeau(3) | AB | 100 | 355 | 1965, 1967 | Alberta PPA | 2020
BC Hydro Facilities |  |  |  |  |  |
Akolkolex (4) (5) | BC | 100 | 10 | 1995 | BC Hydro | 2046
Pingston (4) (5) | BC | 50 | 23 | 2003, 2004 | BC Hydro | 2023
Bone Creek (4) (5) | BC | 100 | 19 | 2011 | BC Hydro | 2031
Upper Mamquam(4) (5) | BC | 100 | 25 | 2005 | BC Hydro | 2025
Ontario Hydro Facilities |  |  |  |  |  |
Appleton (4) | ON | 100 | 1 | 1994 | IESO | 2030
Galetta (4) (7) | ON | 100 | 2 | 1998 | IESO | 2030
Misema (4) | ON | 100 | 3 | 2003 | IESO | 2027
Moose Rapids (4) | ON | 100 | 1 | 1997 | IESO | 2030
Ragged Chute (4) | ON | 100 | 7 | 1991 | IESO | 2029
US Hydro Facilities |  |  |  |  |  |
Skookumchuck (6) | WA | 100 | 1 | 1970 | PSE | 2025
Total Hydroelectric Net Capacity | 926 |  |  |

Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owned, directly or indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) These facilities form part of the "Hydro Assets" subject to the Brookfield Investment. See "General Development of the Business - Three-Year History - 2019 - Strategic Investment by Brookfield Renewable Partners." The Alberta Power Purchase Arrangement in respect of these assets expired on Dec. 31, 2020 and are now operated as merchant.
(4) Facility owned by TransAlta Renewables.
(5) These facilities are EcoLogo® certified. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(6) This facility is used to provide a reliable water supply to Centralia Coal.
(7) Galetta was originally built in 1907, but was retrofitted in 1998.
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Bow River System
Barrier
Barrier is a hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River in Seebe, Alberta. It has been operating since 1947. The facility operated under an Alberta power purchase arrangement ("Alberta PPA") that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates Emission Performance Credits ("EPCs") under the Alberta Technology Innovation and Emissions Reduction (" TIER") system.
Bearspaw
Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. It has been operating since 1954. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Cascade
Cascade is a hydroelectric facility with installed capacity of 34 MW located on the Cascade River in Banff National Park, Alberta. We purchased this facility from the Government of Canada in 1941. The following year, we built a new dam and power plant to replace the original, and then, in 1957, added a second generating unit. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Ghost
Ghost is a hydroelectric facility with installed capacity of 54 MW located on the Bow River in Cochrane, Alberta. It has been operating since 1929. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Horseshoe
Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located on the Bow River in Seebe, Alberta. It has been operating since 1911. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Interlakes
Interlakes is a hydroelectric facility with installed capacity of 5 MW located at Kananaskis Lakes, Alberta. It has been operating since 1955. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Kananaskis
Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located on the Bow River in Seebe, Alberta. It has been operating since 1913. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Pocaterra
Pocaterra is a hydroelectric facility with installed capacity of 15 MW located at Kananaskis Lakes, Alberta. It has been operating since 1955. Generation from the facility is sold in the Alberta spot market and creates EPCs under the TIER system.
Rundle
Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. It has been operating since 1951.The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Spray
Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta, on the Spray system. The plant uses water from the Spray Lakes storage reservoir. It has been operating since 1951. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
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Three Sisters
Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam in Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. It has been operating since 1951. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Waterton-St. Mary River System
Belly River
The Belly River facility is owned by TransAlta Renewables. Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in Southern Alberta. Due to its location along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan. It has been operating since 1991. We acquire the generation from the facility pursuant to a PPA with TransAlta Renewables (a "Renewables PPA"), and subsequently sell such generation in the Alberta spot market.
St. Mary
The St. Mary facility is owned by TransAlta Renewables. St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the dam impounding the St. Mary Reservoir, near Magrath, in southern Alberta. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Taylor
The Taylor facility is owned by TransAlta Renewables. Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System, which is owned by the Government of Alberta. It has been operating since 2000. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Waterton
The Waterton facility is owned by TransAlta Renewables. Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hill Spring, southwest of Lethbridge, Alberta. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
North Saskatchewan River System
Bighorn
Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta. It has been operating since 1972. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Brazeau
Brazeau is a hydroelectric facility with installed capacity of 355 MW located in Drayton Valley, Alberta. It has been operating since 1965. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
BC Hydro Facilities
Akolkolex
The Akolkolex facility is owned by TransAlta Renewables. Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia. It has been operating since 1995. In 2016, TransAlta entered into a new 30-year agreement to sell the output from the facility to the British Columbia Hydro Power Authority ("BC Hydro").
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Bone Creek
The Bone Creek facility is owned by TransAlta Renewables. Bone Creek is a run-of-river hydroelectric facility with installed capacity of 19 MW located on Bone Creek, 90 kilometres south of the town of Valemount, British Columbia. It has been operating since 2011. The output from the facility is under contract with BC Hydro.
Pingston
Pingston is a run-of-river hydroelectric facility with installed capacity of 45 MW located on Pingston Creek, southwest of Revelstoke, British Columbia, and down river of the Akolkolex facility. It has been operating since 2003. TransAlta Renewables owns the facility equally with Brookfield Renewable Power Inc. The output from the facility is sold to BC Hydro under a 20-year agreement that is set to expire in 2023.
Upper Mamquam
The Upper Mamquam facility is owned by TransAlta Renewables. Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver. It has been operating since 2005. The output from the facility is sold to BC Hydro under a PPA that terminates in 2025.
Ontario Hydro Facilities
Appleton
The Appleton facility is owned by TransAlta Renewables. Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario. The facility has been operating since 1994. Generation from this facility is sold to Ontario's Independent Electricity System Operator ("IESO") under a contract that terminates on Dec. 31, 2030.
Galetta
The Galetta facility is owned by TransAlta Renewables. Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW located on the Mississippi River, near Galetta, Ontario. This facility was originally built in 1907 and retrofitted in 1998. Generation from this facility is sold to the IESO under a contract that terminates on Dec. 31, 2030.
Misema
The Misema facility is owned by TransAlta Renewables. Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario. This facility has been operating since 2003. Generation from this facility is sold to the IESO under a contract that terminates on May 3, 2027.
Moose Rapids
The Moose Rapids facility is owned by TransAlta Renewables. Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario. This facility has been operating since 1997. Generation from this facility is sold to the IESO under a contract that terminates on Dec. 31, 2030.
Ragged Chute
The Ragged Chute facility is owned by TransAlta Renewables. Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of Temiskaming Shores, in northern Ontario. We lease this facility from Ontario Power Generation Inc. and it has been operating since 1991. Generation from this facility is sold to the IESO under a contract that terminates on June 30, 2029.
US Hydro Facilities
Skookumchuck Hydro
We own a 1 MW hydroelectric generating facility on the Skookumchuck River near Centralia, Washington, and related assets that are used to provide water supply to our generation facilities in Centralia. On Dec. 7, 2020, we entered into an agreement with Puget Sound Energy for Skookumchuck to provide power until 2025.
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Wind and Solar Business Segment
As at Dec 31, 2020, the Wind and Solar segment held interests in approximately 1,544 MW of net wind generating capacity. This capacity consists of 10 wind facilities in Western Canada, 4 in Ontario, 2 in Québec, 3 in New Brunswick and 5 in the United States, more specifically in the states of Wyoming, Minnesota, Pennsylvania, Washington and New Hampshire. The Corporation also holds a 10 MW utility-scale battery storage in Alberta and an interest in a 21 MW solar facility in the state of Massachusetts.
Wind and solar are not generally a dispatchable fuel. Therefore, in merchant markets, wind and solar assets may not be able to secure the annual average pool price. As such, we make different assumptions in forecast revenue received for generation from a wind or solar asset compared to a base load asset. If these price assumptions and generation production forecasts are not correct, the corresponding revenue received may be reduced. Generation production forecasts are based on the long-term average production forecast for a site, reflecting historical climatic conditions. Within any year there may be variations from this long-term average. In order to forecast generation production, a number of factors have to be assumed based on historic on-site data. For a wind facility, this includes wind facility design including wake and array losses, wind shear and the electrical losses within the site. For a solar facility, long-term energy production depends on panel angle and row spacing, amount of sun, ambient conditions such as temperature and wind speed and losses at the site. If these assumptions are incorrect then actual production will be higher or lower than the long-term forecast for the site.
As well as contracting for the sale of the power generated, we also enter into long-term and short-term contracts to sell the environmental attributes from the merchant wind facilities, including offsets and RECs. These activities help to ensure earnings consistency from these assets. Generally, for facilities under long-term contract, the purchaser under such long-term contracts also has the benefit of any environmental attributes.
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The following table summarizes our Wind and Solar generation facilities as at Dec. 31, 2020:

Facility Name | Province/ State | Ownership (%) | Net Capacity Ownership Interest (MW)(1) | Commercial Operation Date | Revenue Source | Contract Expiry Date(2)
Alberta Wind Facilities |  |  |  |  |  |
Ardenville (4) (5) | AB | 100 | 69 | 2010 | Merchant | ‑
Blue Trail and Macleod Flats (4) (5) | AB | 100 | 69 | 2009 and 2004 | Merchant | ‑
Castle River (4) (5) (6) | AB | 100 | 44 | 1997‑2001 | Merchant | -
Cowley North (4) (5) | AB | 100 | 20 | 2001 | Merchant | ‑
McBride Lake (4) (5) | AB | 50 | 38 | 2004 | ENMAX | 2024
Sinnott (4) (5) | AB | 100 | 7 | 2001 | Merchant | ‑
Soderglen (4) (5) | AB | 50 | 35 | 2006 | Merchant | ‑
Summerview 1 (4) (5) | AB | 100 | 68 | 2004 | Merchant | ‑
Summerview 2 (4) (5) | AB | 100 | 66 | 2010 | Merchant | ‑
Alberta Battery Energy Storage |  |  |  |  |  |
WindCharger (4) | AB | 100 | 10 | 2020 | Merchant | ‑
Eastern Canada Wind Facilities |  |  |  |  |
Kent Breeze (4) | ON | 100 | 20 | 2011 | IESO | 2031
Kent Hills 1(4) | NB | 83 | 80 | 2008 | NB Power | 2035
Kent Hills 2 (4) | NB | 83 | 45 | 2010 | NB Power | 2035
Kent Hills 3 (4) | NB | 83 | 14 | 2018 | NB Power | 2035
Le Nordais (4) (5) (7) | QC | 100 | 98 | 1999 | Hydro-Québec | 2033
Melancthon I (4) | ON | 100 | 68 | 2006 | IESO | 2026
Melancthon II (4) | ON | 100 | 132 | 2008 | IESO | 2028
New Richmond (4) (5) | QC | 100 | 68 | 2013 | Hydro-Québec | 2033
Wolfe Island (4) | ON | 100 | 198 | 2009 | IESO | 2029
US Wind and Solar Facilities |  |  |  |  |  |
Antrim (3) | NH | 100 | 29 | 2019 | Partners HealthCare and New Hampshire Electric | 2039
Big Level (3) | PA | 100 | 90 | 2019 | Microsoft | 2034
Lakeswind (3) | MN | 100 | 50 | 2014 | LTC | 2034
Mass Solar (3)(8) | MA | 100 | 21 | 2012-2015 | LTC | 2032-2045
Skookumchuck Wind (3) | WA | 49 | 67 | 2020 | Puget Sound Energy | 2040
Wyoming Wind (3) | WY | 100 | 140 | 2003 | LTC | 2028
Total Wind and Solar Net Capacity (9) | 1,544 |  |  |

Notes:
(1) MW are rounded to the nearest whole number. Column may not add due to rounding. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2019, TransAlta owned, directly and indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) TransAlta Renewables owns an economic interest in the facility.
(4) Facility owned directly by TransAlta Renewables.
(5) These facilities are EcoLogo® certified. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(6) Includes seven additional turbines at other locations.
(7) Comprised of two facilities.
(8) Comprised of multiple facilities.
(9) Excludes Windrise, which is a wind project currently under construction.
All of the electricity generated and sold by our wind generating facilities within Alberta and Quebec, are from facilities that are EcoLogo certified. We are an EcoLogo-certified distributor of alternative source electricity through Environment Canada's Environmental Choice Program.
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Alberta Wind Facilities
Ardenville
The Ardenville facility is owned by TransAlta Renewables. Ardenville is a 69 MW wind facility located approximately eight kilometres south of Fort Macleod, Alberta adjacent to the Macleod Flats wind facility. We constructed the project, which began commercial operations on Nov. 10, 2010. In 2018, the Ardenville wind facility was granted an extension to create offset credits under the TIER Regulation until October 2023 and is entitled to receive ecoENERGY for Renewable Power payments until November 2020. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Blue Trail and Macleod Flats
The Blue Trail facility is owned by TransAlta Renewables. Blue Trail is a 66 MW wind facility located in southern Alberta, that began commercial operations in November 2009. The Blue Trail wind facility creates carbon offset credits under TIER until September 2022 and was entitled to receive ecoENERGY payments until November 2019. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
The Macleod Flats facility is owned by TransAlta Renewables. Macleod Flats consists of a single 3 MW turbine and is located near Fort Macleod. It was commissioned in 2004 and was purchased by us in 2009. This facility generates renewable credits. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Castle River
The Castle River facility is owned by TransAlta Renewables. Castle River is a 44 MW wind facility that consists of 66 Vestas wind turbines (three Vestas V44 600 kW wind turbines and 63 Vestas V47 660 kW wind turbines) on 50 metre towers, and is located southwest of Pincher Creek, Alberta. This facility also includes an additional six turbines, totaling 4 MW, that are located individually in the Cardston County and Hill Spring areas of south western Alberta. This facility began commercial operations in stages from November 1997 through to July 2001. This facility generates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Cowley North
The Cowley North facility is owned by TransAlta Renewables. Cowley North is a 20 MW wind facility that consists of 15 1.3 MW Nordex N60 wind turbines on 65-metre towers, and is located near the towns of Cowley and Pincher Creek, in southern Alberta. This facility began commercial operations in the fall of 2001. The Cowley North wind facility creates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
McBride Lake
The McBride Lake facility is owned by TransAlta Renewables. The 75 MW McBride Lake wind facility, which is equally owned by ENMAX Generation Portfolio Inc., consists of 114 Vestas V47 (660 kW) wind turbines on 50-metre towers, and is located south of Fort Macleod, Alberta. This facility began commercial operations in April 2004. Generation from this facility is sold under a 20-year PPA with ENMAX Energy Corp. that terminates in 2024. This facility generates EPCs under the TIER system.
Sinnott
The Sinnott facility is owned by TransAlta Renewables. Sinnott has a total installed capacity of 7 MW that consists of five, 1.3 MW Nordex N60 wind turbines on 65-metre towers, and is located directly east of the Cowley North wind facility and north of Pincher Creek, Alberta. This facility began commercial operations in the fall of 2001. The Sinnott wind facility creates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Soderglen
The Soderglen facility is owned by TransAlta Renewables. Soderglen is a 71 MW facilitythat consists of 47 1.5 MW GE SLE wind turbines on 65-metre towers, and is located southwest of Fort Macleod. This facility began commercial operations in September 2006. The Soderglen wind facility creates EPCs under the TIER system. TransAlta Renewables owns the facility equally with CNOOC Petroleum North America ULC. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell 50 per cent of such generation in the Alberta spot market (which excludes that portion of generation that is owned by CNOOC Petroleum North America ULC).
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Summerview 1
The Summerview 1 facility is owned by TransAlta Renewables. Summerview 1 is a 68 MW wind facility located approximately 15 kilometres northeast of Pincher Creek, Alberta. We constructed Summerview and it began commercial operations in 2004. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market. The Summerview 1 facility creates EPCs under the TIER system.
Summerview 2
The Summerview 2 facility is owned by TransAlta Renewables. Summerview 2 is a 66 MW wind facility that consists of 38, 1.8 MW Vestas V80 wind turbines on 67- metre towers, and is located approximately 15 kilometres northeast of Pincher Creek, Alberta. This facility began commercial operations in September 2004. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market. The Summerview 2 wind facility expansion creates carbon offset credits under TIER until November 2022, at which time the facility will become an opt-in facility under TIER.
WindCharger
WindCharger is Alberta's first utility-scale battery storage facility. The facility has a nameplate capacity of 10 MW and a total storage capacity of 20 MWh. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek next to the existing Summerview wind facility substation. The energy storage project achieved commercial operations on Oct. 15, 2020. WindCharger stores energy produced by the nearby Summerview 2 wind facility and discharges it into the Alberta electricity grid at times of high-peak demand. The project received co-funding support from Emissions Reduction Alberta. WindCharger was acquired by TransAlta Renewables on Aug. 1, 2020. The Corporation executed a 20-year battery storage usage contract with TransAlta Renewables, whereby the Corporation pays a fixed-monthly capacity charge for the exclusive right to operate and dispatch the battery in the Alberta power market.
Windrise
On Dec. 17, 2018, TransAlta's Windrise project was selected by the AESO as one of three selected projects in the third round of the Renewable Electricity Program. Windrise is a 207 MW wind project situated on 11,000 acres of land located in the county of Willow Creek. The Windrise wind project will consist of 43 Siemens Gamesa 4.8-145 turbines. The wind facility has an executed Renewable Electricity Support Agreement with AESO to provide wind electricity and associated environmental attributes to the province for a 20-year term. Construction of the Windrise wind project began in mid-April 2020 with enhanced COVID-19 safety measures and protocols in place to ensure the safety and well-being of the employees, contractors and the surrounding community. Commercial operation of the Windrise wind project is expected to be achieved in the second half of 2021. TransAlta Renewables acquired the Windrise project on Feb. 26, 2021, although the economic benefit is effective Jan. 1, 2021.
Eastern Canada Wind Facilities
Kent Breeze
Kent Breeze is a 20 MW wind facility located in Thamesville, Ontario and comprises eight 2.5 MW GE wind turbines on 85-metre towers. This facility began commercial operations in 2011. Generation from this facility is sold to the IESO. Kent Breeze is entitled to receive ecoENERGY payments until Dec. 31, 2021. On May 31, 2018, this facility was acquired by TransAlta Renewables. See "General Development of the Business – Three-Year History - Generation and Business Development."
Kent Hills 1
The Kent Hills 1 facility is owned by TransAlta Renewables. The 96 MW Kent Hills 1 wind facility, in which TransAlta Renewables has an 83 per cent interest, comprises 32 3.0 MW Vestas V90 wind turbines on 80-metre towers, and is located near Moncton, New Brunswick. This facility began commercial operations in December 2008. Natural Forces Technologies Inc., a wind developer based in Atlantic Canada, co-developed this project with TransAlta and exercised its option to purchase 17 per cent of the Kent Hills 1 facility in May 2009. Generation from this facility is sold under a 25-year PPA with New Brunswick Power that terminates in 2033. On June 1, 2017, we extended the term of the PPA by two years to 2035.
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Kent Hills 2
The Kent Hills 2 facility is owned by TransAlta Renewables. The 54 MW Kent Hills 2 wind facility expansion, in which the TransAlta Renewables has an 83 per cent interest, comprises 18 3.0 MW Vestas V90 wind turbines on 80-metre towers. Natural Forces Technologies Inc. owns the remaining 17 per cent interest. The facility began commercial operations in November 2010. Generation from this facility is sold under a 25-year PPA with New Brunswick Power that terminates in 2035. Kent Hills 2 received ecoENERGY payments until November 2020.
Kent Hills 3
TransAlta Renewables has an 83 per cent interest in the Kent Hills 3 facility. On June 1, 2017, we signed a PPA with New Brunswick Power for the further expansion of the Kent Hills wind facility. This expansion project, Kent Hills 3, reached commercial operations on Oct. 19, 2018 and added five 3.45 MW turbines to the Kent Hills fleet for an additional 17.25 MW at the site, bringing total generating capacity of the three Kent Hills facilities to 167 MW. The Kent Hills 3 PPA expires in 2035. See "General Development of the Business – Three-Year History - Generation and Business Development."
Le Nordais
The Le Nordais facility is owned by TransAlta Renewables. The 98 MW Le Nordais wind facility is located at two sites: Cap-Chat with 55.5 MW of installed capacity consisting of 74, 750 kW NEG-Micon wind turbines on 55-metre towers; and Matane with 42 MW of installed capacity consisting of 56, 750 kW NEG-Micon wind turbines on 55-metre towers. Le Nordais is located on the Gaspé Peninsula of Québec. It began commercial operations in 1999. Generation from this facility is sold to Hydro-Québec and generates RECs.
Melancthon I
The Melanchton I facility is owned by TransAlta Renewables. Melancthon I is a 68 MW wind facility consisting of 45, 1.5 MW GE wind turbines on 80 metre towers, and is located in Melancthon Township near Shelburne, Ontario. This facility began commercial operations in March 2006. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2026.
Melancthon II
The Melancthon II facility is owned by TransAlta Renewables. Melancthon II is a 132 MW wind facility consisting of 88, 1.5 MW GE wind turbines on 80 metre towers, and is located adjacent to Melancthon I, in Melancthon and Amaranth townships, Ontario. This facility began commercial operations in November 2008. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2028.
New Richmond
The New Richmond facility is owned by TransAlta Renewables. New Richmond is a 68 MW wind facility consisting of 27, 2.0 MW and six, 2.3 MW Enercon E82 wind turbines on 100 metre towers, and is located in New Richmond, Québec. This facility began commercial operations in March 2013. Generation from this facility is sold under a 20-year electricity supply agreement with Hydro-Québec Distribution that terminates in 2033.
Wolfe Island
The Wolfe Island facility is owned by TransAlta Renewables. Wolfe Island is a 198 MW wind facility consisting of 86, 2.3 MW Siemens SWT 93 wind turbines on 80 metre towers, and is located on Wolfe Island, near Kingston, Ontario. This facility began commercial operations in June 2009. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2029.
US Wind and Solar Facilities
Antrim
The Antrim wind facility is 29 MW located in Antrim, New Hampshire. The wind facility was constructed by TransAlta Corporation and was commissioned in December 2019. The wind facility is fully operational and contracted under two long-term PPAs until 2039 with Partners Healthcare and New Hampshire Electric. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Three-Year History - Generation and Business Development."
Big Level
The Big Level wind facility is 90 MW located in Potter County, Pennsylvania. The wind facility was constructed by TransAlta Corporation and commissioned in December 2019. The wind facility is fully operational and contracted under a long-term PPA until 2034 with Microsoft. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares
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from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Generation and Business Development."
Lakeswind
The Lakeswind wind facility is 50 MW located near Rollag, Minnesota. The wind facility was acquired in 2015 from an affiliate of Rockland Capital LLC. The wind facility is fully operational and contracted under a long-term PPA until 2034 with several high-quality counterparties. On May 31, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Generation and Business Development."
Mass Solar
The Mass Solar facility is a 21 MW solar project consisting of multiple facilities located in Massachusetts. The solar facility was acquired in 2015 from an affiliate of Rockland Capital LLC. The operational solar facility is contracted under a long-term PPA with several high-quality counterparties. In addition to revenue generated under the PPA, the project generate solar RECs that expire in 2024. On May 31, 2018 TransAlta Renewables acquired tracking preferred shares from the Corporation that provide TransAlta Renewables with an economic interest in the solar facility. See "General Development of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."
Skookumchuck Wind
The Skookumchuck facility is 137 MW located in Lewis and Thurston counties, Washington. It consists of 38 Vestas V136 wind Turbines. Skookumchuck began commercial operations on Nov. 7, 2020, and has a 20-year PPA with Puget Sound Energy Inc. On Dec. 1, 2020, the Corporation acquired a 49 per cent equity interest in the wind facility from its partner Southern Power Company, a subsidiary of Southern Company. TransAlta Renewables has agreed to acquire the economic interest in Skookumchuck wind facility, which is expected to close in the second quarter of 2021 and the economic benefit will be deemed effective Jan. 1, 2021.
Wyoming
The Wyoming wind facility is 140 MW located near Evanston, Wyoming. It was acquired in December 2013 from an affiliate of NextEra Energy Resources, LLC. The wind facility is contracted under a long-term PPA until 2028 with an investment grade counterparty. TransAlta Renewables holds tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "Non-Controlling Interests – TransAlta Renewables."
North American Gas Business Segment
The following table summarizes our Canadian natural gas-fired generation facilities as at Dec. 31, 2020:

Facility Name | Province/ State | Ownership (%) | Net Capacity Ownership Interest (MW)(1) | Commercial Operation Date | Revenue Source | Contract Expiry Date(2)
Ada | MI | 100 | 29 | 1991 | Consumers Energy/ Amway | 2026
Fort Saskatchewan(5) | AB | 30 | 35 | 1999 | Dow Chemical/Merchant | 2029
Poplar Creek(4) | AB | 100 | 230 | 2001 | Suncor | 2030
Ottawa(5) | ON | 50 | 37 | 1992 | LTC/Merchant | 2022-2033
Sarnia(3) | ON | 100 | 499 | 2003 | LTCs | 2022-2025
Windsor(5) | ON | 50 | 36 | 1996 | IESO/Merchant | 2031
Total North American Gas Net Capacity | 866 |  |  |

Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owns, directly or indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) Facility is owned by TransAlta Renewables.
(4) The Poplar Creek facility is operated by Suncor Energy Inc. and ownership of the facility will transfer to Suncor in 2030.
(5) Our interests in these facilities are through our ownership interest in TransAlta Cogeneration LP ("TA Cogen").
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Ada
Ada is a 29 MW contracted cogeneration facility located in Ada, Michigan. The facility is contracted under a long-term PPA and steam sale agreement. The facility has been in operation since 1991, and consists of a single GE LM2500 gas turbine and an ABB steam turbine and produces approximately 18,000 tonnes of steam hourly. The electricity and steam output of the facility are fully contracted until 2026 with Consumers Energy and Amway. TransAlta completed the acquisition to own and operate the facility on May 19, 2020. On Dec. 23, 2020, TransAlta Renewables agreed to acquire the economic interest in the facility, which is expected to close in the first half of 2021 and the economic benefit will be deemed effective Jan. 1, 2021.
Fort Saskatchewan
We have a net ownership interest of 30 per cent in the Fort Saskatchewan facility. See "Business of TransAlta – Non-Controlling Interests." The 118 MW natural gas-fired combined-cycle cogeneration Fort Saskatchewan facility is owned by TA Cogen and Prairie Boys Capital Corporation. During the fourth quarter of 2017, we entered into a long-term contract for the Fort Saskatchewan facility providing for the delivery of energy and steam to the customer. The contract has an initial 10-year term, which began on Jan. 1, 2020, with the option for two five-year extensions. The contract allows our customer to continue to benefit from the operational flexibility of the facility.
Poplar Creek
Our Poplar Creek facility is located in Fort McMurray, Alberta. On Aug. 31, 2015, the Corporation restructured its contractual arrangement for the facility's power generation services. The Poplar Creek cogeneration facility had been built and contracted to provide steam and electricity to Suncor's oil sands operations. Under the terms of the new arrangement, Suncor acquired from the Corporation two steam turbines with an installed capacity of 126 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the cogeneration facility and has the right to use the full 230 MW capacity of the Corporation's gas generators until Dec. 31, 2030. Ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.
Ottawa
The Ottawa facility is owned by TA Cogen. See "Business of TransAlta – Non-Controlling Interests." It is a combined-cycle cogeneration facility designed to produce 74 MW of electrical energy. On Aug. 30, 2013, the Corporation announced the recontracting of the facility with the IESO for a 20-year term, effective January 2014. The Ottawa facility also provides steam, hot water, and chilled water to the member hospitals and treatment centres of the Ottawa Health Sciences Centre and the National Defence Medical Centre. The thermal energy contract with the Ottawa Health Sciences Centre expires Jan. 1, 2024.
Sarnia
The Sarnia facility is a 499 MW combined-cycle cogeneration facility located in Sarnia, Ontario, that provides power and steam to nearby industrial facilities owned by ARLANXEO Canada Inc. (formerly LANXESS AG, successor to Bayer Inc.), Nova Chemicals Corporation (Canada) Ltd. ("NOVA") (which in turn supplies INEOS Styrolution, a styrene production facility formerly owned by NOVA) and Suncor Energy Products Partnership under contracts terminating in 2022. We are currently evaluating potential extensions to these power and steam off-take agreements. The facility also provides electricity to the IESO under a contract that terminates Dec. 31, 2025.
The Sarnia facility uses three Alstom 11N2 gas turbines, each capable of generating between 102 MW and 118 MW, one condensing steam turbine that can produce 120 MW, and back-pressure steam turbines capable of generating 56 MW. The facility also incorporates a fired boiler, river water pump houses, and water treatment plants. In 2018, Sarnia's capacity was reduced from 506 MW to 499 MW due to the lay-up of one generator. The reduction in capacity has not impacted the facility's ability to meet its contractual requirements.
Windsor
The Windsor facility is owned by TA Cogen. See "Business of TransAlta – Non-Controlling Interests." It is a combined-cycle cogeneration facility designed to produce 72 MW of electrical energy, of which, 50 MW was sold under a long-term contract to the Ontario Electricity Financial Corporation that expired Nov. 30, 2016. Effective Dec. 1, 2016, the Windsor facility began operating under an agreement with the IESO with a 15-year term for up to 72 MW of capacity. The Windsor facility also provides thermal energy to Stellantis Canada's minivan assembly facility in Windsor under a contract that expires in Nov. 2022, with six successive renewal terms of one year each.
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Kaybob Cogeneration
In 2019, TransAlta and ET Canada entered into agreements to develop, construct and operate a 40 MW cogeneration facility at K3. The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sep. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada.
Australian Gas Business Segment
The following table summarizes our Australian assets as at Dec. 31, 2020:

Facility Name | Province/ State | Ownership (%) | Net Capacity Ownership Interest (MW)(1) | Commercial Operation Date | Revenue Source | Contract Expiry Date
Parkeston(2)(3) | WA(4) | 50 | 55 | 1996 | Newmont Power Pty Ltd. | 2026
South Hedland(2) | WA(4) | 100 | 150 | 2017(5) | LTCs(5) | 2042
Southern Cross Energy(2)(6) | WA(4) | 100 | 245 | 1996 | BHP Billiton Nickel West Pty Ltd | 2038
Fortescue River Gas Pipeline | WA(4) | 43 | N/A | 2015 | Fortescue Metals Group | 2035
Total Australian Gas Net Capacity | 450 |  |  |

Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owned approximately 60 per cent of the common shares in TransAlta Renewables.
(2) TransAlta Renewables owns an economic interest in the facility.
(3) Plant contracted to October 2026 with early termination options beginning in 2021.
(4) Western Australia.
(5) Fortescue Metals Group ("FMG") is contracted for 23 per cent of the capacity, with Horizon Power contracting for the remaining 77 per cent of capacity. FMG is disputing the Corporation's declaration of commercial operation. See "Legal Proceedings and Regulatory Actions."
(6) Comprised of four facilities.
All of our Australian assets are owned, directly or indirectly, by TransAlta Energy (Australia) Pty Ltd. ("TEA"), a wholly-owned subsidiary of TransAlta. On May 7, 2015, TransAlta Renewables acquired tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows broadly equal to the underlying net distributable cash flow of TEA, in consideration for a payment equal to $1.78 billion, which amount included funding the remaining construction costs for South Hedland.
Pursuant to the terms of the tracking preferred shares, TransAlta Renewables is entitled to receive, in priority to the common shares in the capital of TEA, quarterly preferential cash dividends. The preferred shares have no residual right to participate in the earnings of TEA. In the event of the liquidation, dissolution or winding-up of TEA or any other distribution of the assets of TEA among its shareholders for the purpose of winding up its affairs, TransAlta Renewables is entitled, subject to applicable law, to receive from TEA as the sole holder of preferred shares, before any distribution of TEA to the holders of the common shares or any other shares ranking junior to the preferred shares, an amount equal to the fair market value of the Australian assets.
Parkeston
The Parkeston facility is a 110 MW dual-fuel natural gas and diesel-fired power station, which we own in partnership through a 50/50 joint venture with NP Kalgoorlie Pty Ltd., a subsidiary of Newmont Australia Limited. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines and the initial supply contract ended in 2016. The facility was recontracted effective Nov. 1, 2016, and the agreement extends the previous contract to October 2026, with options for early termination available to either party beginning in 2021. We are evaluating potential opportunities to renew or extend the supply contract. Any merchant capacity and energy are sold into Western Australia's wholesale electricity market. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Parkeston facility on May 7, 2015.
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Southern Cross
Southern Cross Energy is consists of four naturalgas and diesel-fired generation facilities with a combined capacity of 245 MW. Southern Cross Energy sells its output under a contract with BHP Billiton Nickel West, which was renewed in October 2013 for 10 years. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Southern Cross Energy facilities on May 7, 2015.
On Oct. 22, 2020, Southern Cross Energy replaced and extended its current PPA with BHP Nickel West. The new agreement became effective Dec. 1, 2020 and replaced the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038 and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross facilities for BHP Nickel West's mining operations located in the Goldfields region of Western Australia. The extension provides SCE a return of and on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiative under the extended PPA with SCE are underway, including an 18.5 MW solar photovoltaic facility supported by a battery energy storage system and a waste heat steam turbine system.
South Hedland
The South Hedland Power Station is a 150 MW combined-cycle power station located near South Hedland, Western Australia. Construction began in early 2015 and the plant achieved commercial operation on July 28, 2017. The facility was fully contracted with two customers for a 25-year term. Most of the facility's capacity remains contracted to Horizon Power, the state-owned electricity supplier in the region. The second customer is the port operations of FMG for 35 MW of capacity. In November 2017, we received a notice from FMG purporting to terminate their PPA. We have disputed this notice and are currently in litigation with FMG in respect of this dispute. This matter was adjourned due to the COVID-19 pandemic and is rescheduled to proceed to trial for five weeks starting May 3, 2021. See "Legal Proceedings and Regulatory Actions" for further details. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the South Hedland facility on May 7, 2015.
Fortescue River Gas Pipeline
In 2014, we established the Fortescue River Gas Pipeline joint venture with DBP Development Group. The joint venture (of which TransAlta is a 43 per cent partner) was successfully awarded the contract to design, build, own and operate the 270- kilometre Fortescue River Gas Pipeline to deliver natural gas to the Solomon facility. The pipeline was completed in the first quarter of 2015 and operates under a take-or-pay gas transport agreement with a subsidiary of FMG for an initial term of 20 years. The 16-inch diameter pipeline has an initial free-flow capacity of 64 terajoules (TJ) per day. Under the gas tariff agreement, FMG has the option to purchase the Fortescue River Gas Pipeline commencing March 2020. FMG maintains its option and the joint venture continues to deliver natural gas transportation to the Solomon facility. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the pipeline on May 7, 2015.
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Alberta Thermal Business Segment
The following table summarizes our Alberta Thermal generation facilities as at Dec. 31, 2020:

Facility Name | Province | Ownership (%) | Net Capacity Ownership Interest (MW)(1) | Commercial Operation Date | Revenue Source | Contract Expiry Date
Keephills Unit No. 1 (2)(3) | AB | 100 | 395 | 1983 | Alberta PPA/Merchant | 2020
Keephills Unit No. 2 (2) | AB | 100 | 395 | 1984 | Alberta PPA/Merchant | 2020
Keephills Unit No. 3 | AB | 100 | 463 | 2011 | Merchant | -
Sheerness Unit No. 1 (2) | AB | 25 | 100 | 1986 | Alberta PPA/Merchant | 2020
Sheerness Unit No. 2 (2) | AB | 25 | 100 | 1990 | Alberta PPA | 2020
Sundance Unit No. 4 (4) | AB | 100 | 406 | 1977 | Merchant | -
Sundance Unit No. 5 (5) | AB | 100 | 406 | 1978 | Merchant | -
Sundance Unit No. 6 | AB | 100 | 401 | 1980 | Merchant | -
Pioneer Pipeline (5) | AB | 50 | N/A | 2019 | LTC | 2034
Total AB Thermal Net Capacity | 2,666 |  |  |

Notes:
(1) MW are rounded to the nearest whole number. Column may not add due to rounding.
(2 )The Alberta Power Purchase Arrangement in respect of these assets expired on Dec. 31, 2020 and are now operated as merchant.
(3) The Corporation will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022 and, as a result, the maximum capability of this unit will be reduced to 70 MW.
(4) The Corporation will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022 and, as a result, the maximum capability of this unit will be reduced to 113 MW.
(5) Unit mothballed to Nov. 1, 2021.
(6) TransAlta. and its partner, Tidewater, entered into a definitive Purchase and Sale Agreement providing for the sale of the Pioneer Pipeline to ATCO, which is expected to close in the first half of 2021.
The Keephills and the Sundance facilities are located approximately 70 kilometres west of Edmonton, Alberta, and are wholly-owned by TransAlta.
On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Alberta PPAs for Sundance Unit B (3 & 4) and Unit C (5 & 6) effective March 31, 2018. As a result, Sundance 4 and 6 have since been operating on a merchant basis within the Alberta market. Upon the expiry of the Alberta PPAs on Dec. 31, 2020, Keephills 1 and 2 units are now merchant and dispatched to take advantage of price volatility in the Alberta energy-only electricity market and to provide ancillary services and, as such, are part of our Alberta electricity portfolio optimization activities.
As part of our Clean Energy Investment Plan, the Corporation is converting coal-fired units into gas-fired units through either a simple boiler conversion, or a more involved project to build a repowered combined-cycle unit using existing and new assets. Our current plan involves three boiler conversions for Sundance 6, Keephills 2 and Keephills 3 to be completed by 2021, and completion of a repowered combined-cycle unit for Sundance 5 by end of 2023. We will continue to actively deplete our coal stock and will wind down our mining activity in Alberta by the end of 2021. As a result, the Corporation announced that Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022. The maximum capability of these units will be reduced to 70 MW and 113 MW, respectively.
During 2020, the Sundance 5 and Keephills 1 repowering projects received approvals from both the AUC and Alberta Environment and Parks to repower these respective units into combined-cycle units. The regulatory permits allow the steam turbines of these units to be repowered by installing combustion turbines and heat recovery steam generators thereby creating highly efficient combined-cycle units. Capital costs of repowered units are estimated to be 60 to 70 per cent of the capital investment as compared to a new combined-cycle facility while achieving a similar heat rate.
The Alberta Thermal fleet is currently subject to the federal-"Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations" and subsequent amendments as long as the units are coal-fired. Once converted to natural-gas-fired, the units become subject to the "Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity." Performance tests will be performed initially and annually to determine the gross
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emissions intensity of a converted unit. The results of the initial performance test will determine the life extension years for a converted unit post conversion.
Sundance 6
Sundance 6 was a coal-fired unit that recently completed its conversion to gas, with its commercial operation as a converted gas-fired unit having been achieved in early 2021. Under the federal gas-fired regulations, we expect this unit's intensity factor to be at or below 550 tonnes of CO 2 emissions per GWh, thereby adding an additional eight years of life.
Keephills 2
Keephills Unit 2 is a coal-fired unit that will begin its conversion to gas in the spring of 2021 and will reach commercial operations by the first half of 2021. Under the federal gas-fired regulations, we expect this unit's intensity factor to be at or below 550 tonnes of CO 2 emissions per GWh, thereby adding an additional eight years of life.
Keephills 3
Keephills Unit 3 will begin its conversion to gas in the fall of 2021 and will reach commercial operations by the second half of 2021. Under the federal gas-fired regulation, we expect this unit's intensity factor to be at or below 480 tonnes CO 2 emissions per GWh, thereby adding an additional 10 years of life. Useful life for this unit is estimated to be through to 2039.
Sundance 5
The Sundance Unit 5 repowering project is on-track to start construction in March 2021. The project will be utilizing the Three Creeks assets acquired by Kineticor in 2019 to construct a highly-efficient combined-cycle unit. Sundance Unit 5's existing steam turbine will be paired with the two existing Siemens F class gas turbines from the Three Creeks acquisition and two new heat recovery steam generators. This combination of technology will increase the unit's current generation capability of 406 MW to 729 MW into the Alberta grid. All power generated will be from natural gas reducing the unit's emission intensity by over 55 per cent. Also, with the addition of a selective catalytic reducer the expected NOx emissions will be 7ppmvd, well below the provincial standard of 15ppmvd. The advantage of the project is that it uses existing infrastructure (including water, transmission, gas, buildings, control room, warehouses) thereby reducing the impact to the environment while keeping capital costs low. The repowered Sundance Unit 5 is expected to reach commercial operation in the fourth quarter of 2023.
Under the federal gas-fired regulation, we expect this unit's intensity factor to be well below 420 tonnes of CO 2 emissions per GWh, thereby adding an additional 25 years of life. Useful life for this unit is estimated to be through to 2048.
Keephills 1 and Sundance 4
As the Corporation will discontinue all mining operations at Highvale mine by the end of 2021, effective Jan. 1, 2022, Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal. These units will only operate on gas, resulting in the maximum capability of these units being reduced to 70 MW and 113 MW respectively. The Corporation continues to evaluate these units as candidates for boiler conversion or full repowering based on market fundamentals.
Sheerness 1 and 2
The Sheerness facilities are located approximately 200 kilometres northeast of Calgary, Alberta, and are jointly-owned by TA Cogen and Heartland Generation Ltd. ("Heartland"). Heartland is responsible for the operation and maintenance of these units. During the first quarter of 2020, Sheerness Unit 2 was converted by Heartland to natural gas, and may be operated as a dual-fuel (coal or gas) unit. Also during 2020, Sheerness Unit 2's capacity was increased from 390 MW to 400 MW following a generator rewind and final testing. In the first quarter of 2021, Sheerness Unit 1 is scheduled to be converted by Heartland to natural gas, and may be operated as a dual-fuel (coal or gas) unit. Coal for the Sheerness facilities is provided from the adjacent Sheerness mine. The Sheerness facility will receive it's last coal shipment in the first quarter of 2021, with coal stock being actively depleted until the end of 2021.
The generation from Sheerness was sold under an Alberta PPA that expired Dec. 31, 2020. Commencing Jan. 1, 2021, each owner separately offers their share of generation into the Alberta energy market starting. See "Business of TransAlta – Non-Controlling Interests."
Mothball of Sundance Units
On April 1, 2018, we mothballed Sundance Unit 3 and Sundance Unit 5. In early 2019, the AESO granted an extension to the continued mothballing of Sundance Units 3 and 5. Sundance Unit 3 was subsequently retired from service on July 31, 2020. The Sundance Unit 5 will remain mothballed up to Nov. 1, 2021 (extended from April 1, 2020). The extension was
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requested by TransAlta based on our assessment of market prices and market conditions. TransAlta has the ability to return Sundance Unit 5 back to full operation by providing three months' notice to the AESO.
The decision to mothball selected units ensures that the remaining units operate at high-capacity utilization factors and competitive cost structures. See "General Development of the Business - Three-Year History - Generation and Business Development."
Sundance 1, 2 and 3
On Jan. 1, 2018, we retired Sundance Unit 1 and mothballed Sundance Unit 2. On July 31, 2018, we permanently retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size and the capital requirements needed to return the unit to service. The retirement is consistent with our strategy to transition to clean electricity .
On July 31, 2020, the Corporation retired the Sundance Unit 3. The retirement decision was driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta.
Keephills 3 and Genesee 3 Swap
On Oct. 1, 2019 TransAlta and Capital Power completed an agreement to swap interests in the Keephills 3 facility and the Genesee 3 facility. As a result, TransAlta now owns 100 per cent of the Keephills 3 facility and Capital Power now owns 100 per cent of the Genesee 3 facility. On closing of the transaction, all of the Keephills 3 and Genesee 3 project agreements with Capital Power were terminated.
Highvale Mine
Fuel requirements for the Alberta thermal coal generation facilities that we operate and have yet to convert to gas generation are currently supplied by a surface strip coal mine located in close proximity to the facilities. We own the Highvale mine that supplies coal to the Sundance and Keephills facilities and perform the mining, reclamation and associated work at the Highvale mine. Furthering the Clean Energy Investment Plan, the Corporation has announced that it will discontinue all mining operations at Highvale mine by the end of 2021. The mine will enter its reclamation phase thereafter.
We also own the Whitewood mine, which formerly supplied coal to the now decommissioned Wabamun facility. The Whitewood mine is no longer in operation and we have completed reclamation of the site.
Off-Coal Agreement
On Nov. 24, 2016, we entered into the Off-Coal Agreement with the Government of Alberta pertaining to our cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired facilities. The Off-Coal Agreement provides that we are entitled to receive annual cash payments of approximately $37.4 million, net to TransAlta, from the Government of Alberta commencing in 2017, and terminating in 2030, subject to satisfaction of certain terms and conditions including our cessation of all coal-fired emissions on or before Dec. 31, 2030. Other conditions include maintaining prescribed spending on investment and investment-related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), maintaining spending on programs and initiatives to support the communities surrounding the facilities and the employees of the Corporation negatively impacted by the phase-out of coal generation, and the fulfillment of all obligations to affected employees, in each case as prescribed by the Off-Coal Agreement. See "General Development of the Business - Three-Year History - Generation and Business Development."
Pioneer Pipeline
We currently have a 50% ownership in the Pioneer Pipeline, which transports natural gas to the Keephills and Sundance facilities. We and Tidewater each own a 50 per cent interest in the Pioneer Pipeline which is backstopped by a 15-year take-or-pay agreement from TransAlta at market rate tolls.
TransAlta and its partner, Tidewater, entered into a definitive sale of the pipeline with ATCO that is expected to receive regulatory approval and close in the first half of 2021. Following closing of the sale, Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations.
In addition, TransAlta has entered into incremental long-term firm natural gas delivery transportation agreements with NGTL for 275 TJ per day, bringing the total long-term firm natural gas transportation contracts up to 400 TJ per day by 2023. TransAlta’s current commitments, including its 139 TJ per day supply arrangement with Tidewater, will remain in place until the closing of the sale of the Pioneer Pipeline to ATCO.
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Centralia Business Segment
Our Centralia facilities are summarized in the following table as at Dec. 31, 2020:

Facility Name | Province/ State | Ownership (%) | Net Capacity Ownership Interest (MW) | Commercial Operation Date | Revenue Source | Contract Expiry Date
Centralia Thermal No. 1 | WA | 100 | 670 | 1971 | LTC/Merchant | 2020
Centralia Thermal No. 2 | WA | 100 | 670 | 1971 | LTC/Merchant | 2025
Total Centralia Net Capacity (1) |  |  | 1,340 |  |  |

Note:
(1) Centralia Unit 1 retired Dec. 31, 2020.
We own a 670 MW thermal coal-fired facility in Centralia, Washington, located south of Seattle. The Centralia Thermal Unit No. 1 retired on Dec. 31, 2020, resulting in the net capacity being reduced from 1,340 MW to 670 MW pursuant to the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill''), which allowed the Centralia thermal facility to comply with the Washington State's GHG emissions performance standards by ceasing coal generation in one of its two boilers by the end of 2020, and the other by the end of 2025. The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility and limiting the technology that the facility would be required to implement for NOx controls. Centralia Unit 2 will retire effective Dec. 31, 2025.
On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from our Centralia thermal facility to Puget Sound Energy. The contract began in 2014 and runs until 2025 when the facility is scheduled to stop burning coal. Under the agreement, Puget Sound Energy bought 180 MW of firm, base-load power starting in December 2014. In December 2015, the contract volume increased to 280 MW and from December 2016 to December 2024 the contract is for 380 MW. In 2025, the contracted volume is for 300 MW.
On July 30, 2015, we announced that we were moving ahead with plans to invest US$55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of Centralia's transition from coal-fired operations in Washington, beginning on Dec. 31, 2020. The US$55- million community investment is part of the Bill passed in 2011. The Bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing Centralia facility's two coal units, one in 2020, and the other in 2025. Approved funding for the three boards totals approximately US$41.3 million as at Dec. 31, 2020.
We sell electricity from the Centralia thermal facility into the Western Electricity Coordinating Council and, in particular, on the spot market in the U.S. Pacific Northwest energy market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.
We also own a coal mine adjacent to the Centralia facility. We stopped mining operations at our Centralia coal mine on Nov. 27, 2006. Although we estimate that certain coal reserves remain to be extracted, we have not yet received permits for, nor developed the new area from which this coal could be produced. Coal to fuel the Centralia facility is sourced from the Powder River Basin in Montana and Wyoming. TransAlta is currently party to coal contracts that expire at the end of 2025.
In December 2014, we began fine coal recovery operations at our Centralia mine. This operation recovers previously wasted coal as part of the mine reclamation process.
Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all citations at its Centralia mine. The mine is currently not in operation and there were no injury incidents reported at the mine during 2020. The total dollar value of all Mine Safety and Health Administration ("MSHA") assessments are not material. Centralia successfully petitioned to assess a civil penalty before the Federal Mine Safety and Health Review Commission involving the Centralia mine during 2020. The petition was settled which resulted in a reduction of the assessment from "Negligence - Moderate" to "Negligence - None."
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Mine or Operating Name/MSHA Identification Number | Total Number of Section 104 Violations for which Citations Received (#) | Total Number of Orders Issued Under Section 104(b) (#) | Total Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards Under Section 104(d) (#) | Total Number of Flagrant Violations Under Section 110(b)(2) (#) | Total Number of Imminent Danger Orders Issued Under Section 107(a) (#) | Total Dollar Value of MSHA Assessments Proposed ($) | Total Number of Mining Related Fatalities (#) | Received Notice of Pattern Violations Under Section 104(e) (yes/no) | Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no) | Legal Actions Initiated or Pending During Period (#)
4500416 | 15(1) | 0 | 0 | 0 | 0 | 7,524 (2) | 0 | No | No | 0

Notes:
(1) Section 104 Violations: TransAlta Centralia Mining and Coalview Centralia LLC.
(2) Citations in Contest: Coalview Centralia LLC (104a - $3,573).
Energy Marketing Segment
Our Energy Marketing segment provides a number of strategic functions, including the following:
▪gathering and analyzing market trends to enable more effective strategic planning and decision making;
▪negotiating and entering into contractual agreements with customers for the sale of output from our generation assets, including electricity, steam or other energy-related commodities;
▪actively engaging in the trading of power, natural gas and environmental products across a variety of markets;
▪negotiating and managing fuel supply arrangements with third parties for our generation assets. This includes scheduling, billing and settlement of physical deliveries of natural gas and other fuels;
▪developing and executing our corporate hedging strategy within Board- approved parameters; and
▪optimizing the asset fleet to maximize gross margin and mitigation of market risks.
The Energy Marketing segment also derives additional revenue by providing fee-based asset management services to third parties, earning margins on third-party gas and power transactions, and by trading electricity and other energy commodities (i.e. fuels). The origination and trading activities are primarily focused on the existing asset and customer footprint of the Corporation.
The segment seeks to measure and manage a number of risks for the assets and for our trading books. The key risk control activities of the Energy Marketing segment include the measurement and management of market, credit, operational, reputational, compliance and legal risks.
The segment uses Value at Risk , Gross Margin at Risk , and tail risk measures to monitor and manage the risks within our asset and trading portfolios. Value at Risk and Gross Margin at Risk measure the potential losses that could occur over a given time period due to changes in market risk factors. Back tests are used to provide further sensitivities to the market risks within the portfolio. Compliance, reputational and legal risks are managed within our legal and compliance policies, and monitoring tools are used to flag compliance risks. The Energy Marketing segment actively manages the risks within approved limits and our policies.
Corporate Segment
Our Corporate segment includes the Corporation's central finance, legal, administrative, business development and investor relations functions.
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Non-Controlling Interests
Our subsidiaries and operations in which we have non-controlling interests are as follows:
TransAlta Renewables
As at Dec. 31, 2020, the Corporation held, directly and indirectly, approximately 60 per cent of the issued and outstanding common shares in TransAlta Renewables, which is a publicly traded entity. We remain committed to maintaining our position as the majority shareholder of TransAlta Renewables.
TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management, Administrative and Operational Services Agreement between TransAlta Corporation and TransAlta Renewables. In connection with the services provided under the Management, Administrative and Operational Services Agreement, TransAlta Renewables pays us an annual fee, which is meant to cover the management, administrative, accounting, planning and other head office costs we incur in connection with providing services to TransAlta Renewables under the Management, Administrative and Operational Services Agreement (the "G&A Reimbursement Fee"). The G&A Reimbursement Fee is payable in equal quarterly installments. On Feb. 28, 2020, the Management Agreement was amended so that the G&A Reimbursement Fee will be calculated quarterly in an amount equal to five per cent of comparable EBITDA of the immediately prior fiscal quarter, without duplication for any indirect costs associated with the management, administrative, accounting, planning and other head office costs of TransAlta that reduce the dividends or distributions that would otherwise be payable to the Corporation on any of the tracking preferred shares. This amendment is not expected to result in any material change to the amount of the G&A Reimbursement Fee. On Aug. 19, 2020, the Management Agreement was amended to clarify comparable EBITDA calculated before taking into account the G&A Reimbursement Fee. During 2020, the G&A Reimbursement Fee was approximately $17 million.
TransAlta Renewables completed its initial public offering in August 2013. In connection with the offering, we transferred to TransAlta Renewables certain wind and hydro power generation assets. On Dec. 20, 2013, we sold to TransAlta Renewables an economic interest in a 140 MW wind facility located in the State of Wyoming for payment equal to US$102 million. The Wyoming wind facility is managed by TransAlta under the terms of the Management, Administrative and Operational Services Agreement and is operated by NextEra Energy Resources, LLC.
On May 7, 2015, we sold to TransAlta Renewables an economic interest based on the cash flows of our Australian assets. The portfolio, held by TEA, consists of six operating assets with an installed capacity of 450 MW as well as a 270 kilometre gas pipeline. The combined value of the Australian transaction was approximately $1.78 billion. At the closing of the Australian transaction, TransAlta Renewables paid us $216.9 million in cash as well as approximately $1,067 million through the issuance of a combination of common shares and Class B shares in the capital of TransAlta Renewables. On Aug. 1, 2017, the Class B shares converted into common shares in the capital of TransAlta Renewables.
On Jan. 6, 2016, we sold to TransAlta Renewables an economic interest in the Corporation's Sarnia cogeneration plant, Le Nordais wind facility and Ragged Chute hydro facility for a combined value of $540 million. The Canadian assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Québec. The Corporation received cash proceeds of $172.5 million, a $215 million convertible unsecured subordinated debenture and approximately $152.5 million in common shares of TransAlta Renewables. In November 2016, the economic interest was converted to direct ownership of the entities that own the Sarnia cogeneration plant, Le Nordais wind facility and Ragged Chute hydro facility. The convertible debenture was redeemed on Nov. 9, 2017.
On May 31, 2018, we sold to TransAlta Renewables an economic interest in the Corporation's 50 MW Lakeswind wind facility in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, we sold to TransAlta Renewables the 20 MW Kent Breeze wind facility located in Ontario. The total purchase price payable to TransAlta for the three assets, which have an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt.
On Dec. 23, 2020, the Corporation and TransAlta Renewables announced it had entered into a definitive agreement for the acquisition of three assets consisting of: (a) a 100 per cent direct interest in the 207 MW Windrise project located in the Municipal District of Willow Creek, Alberta; (b) a 49 per cent economic interest in the 137 MW Skookumchuck wind facility in operation located across Thurston and Lewis counties in Washington State; and (c) a 100 per cent economic interest in the 29 MW Ada facility in operation located in Ada, Michigan. TransAlta Renewables agreed to acquire the portfolio for a total acquisition cost of $439 million and includes the funding of the remaining construction costs for the Windrise wind project.
The Management, Administrative and Operational Services Agreement has an initial 20-year term; it provides, however, that the agreement shall be automatically renewed for further successive terms of five years after the expiry of the initial term or any renewal term, unless terminated by either party not less than 180 days before the expiration of the initial term or any renewal term, as the case may be. The Management, Administrative and Operational Services
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Agreement may be terminated by: (a) mutual agreement; (b) TransAlta Renewables upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by TransAlta Renewables or (ii) upon a "Change of Control" of TransAlta Renewables, being the acquisition by any person or group of persons acting jointly and in concert (other than us and our affiliates) of more than 50 per cent of the issued and outstanding common shares. In addition, the Management, Administrative and Operational Services Agreement may be terminated by TransAlta Renewables by a majority vote of our independent directors at any time if TransAlta's direct and indirect ownership in TransAlta Renewables falls below 20 per cent.
Kent Hills
We indirectly hold, through our share ownership of TransAlta Renewables, an 83 per cent interest in the 150 MW Kent Hills 1 and 2 wind facility located in New Brunswick. We also indirectly hold, through our ownership of TransAlta Renewables, an 83 per cent interest in the 17.25 MW expansion of the Kent Hills site (Kent Hills 3) that was completed on Oct. 19, 2018, bringing the total generating capacity of the three Kent Hills fleet to 167 MW. A description of the facilities is provided under the heading "General Development of the Business – Three-Year History - Generation and Business Development."
TA Cogen
We hold a 50.01 per cent limited partnership interest in TA Cogen, which is an Ontario limited partnership. The remaining 49.99 per cent ownership is held by Canadian Power Holdings Inc., a subsidiary of CK Infrastructure Holdings Limited.
TA Cogen holds a 50 per cent interest in the 800 MW Sheerness thermal generation facility in Alberta and the 118 MW Fort Saskatchewan natural -gas fired cogeneration facility in Alberta. TA Cogen also holds an interest in two natural gas-fired cogeneration facilities located in Ontario: (i) the 74 MW Ottawa plant; and (ii) the 72 MW Windsor plant. Descriptions of these facilities, ownership levels and contract expiry dates are provided under the headings "North American Gas Business Segment" and "Alberta Thermal Business Segment" in this AIF.
PPAs
Renewables PPAs
In August 2013, we entered into long-term PPAs with certain subsidiaries of TransAlta Renewables (each a "Merchant Subsidiary") providing for the purchase by TransAlta, for a fixed price, of all of the power produced at the Merchant Subsidiaries (the "Renewables PPAs"). The initial price payable in 2013 by TransAlta for output under the Renewables PPAs was $30.00/MWh for wind facilities and $45.00/MWh for hydroelectric facilities, and these amounts are adjusted annually for changes in the Canadian consumer price index. The Canadian consumer price index adjusted prices for 2020 were $33.52 per MWh for wind facilities and $50.29 per MWh for hydroelectric facilities. Under the terms of each Renewables PPA, the Merchant Subsidiary is under no obligation to deliver any specified amount of energy and, in no event, shall any penalties or curtailment payments be payable under the Renewables PPA. The Merchant Subsidiary will assume all operating and generating risk and TransAlta will only be required to purchase power that is actually produced.
Each Renewables PPA has a term of 20 years or end-of-asset life, where end-of-asset life is less than 20 years. Each Renewables PPA may be terminated by: (a) the mutual agreement of the parties; (b) the Merchant Subsidiary upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by the Merchant Subsidiary; (ii) upon a change of control of TransAlta Renewables; or (iii) upon a change of control of the Merchant Subsidiary.
Alberta PPAs
Until Dec. 31, 2020, many of our Alberta thermal and hydroelectric facilities had operated under Alberta PPAs that established committed capacity and electrical energy generation requirements and availability targets to be achieved by each thermal facility, energy and ancillary services obligations for the hydroelectric facilities, and the price at which electricity is to be supplied. We held the risk or retained the benefit of availability under or above a targeted availability (except for those arising from events considered to be force majeure, in the case of the PPA thermal facilities) and any change in costs (unless due to a change in law) required to maintain and operate the facilities.
In early 2016, the buyers gave notice to the Balancing Pool of the termination of the Alberta PPAs for Sundance A, B, and C, Sheerness, and Keephills. The Balancing Pool confirmed the terminations of the PPAs for Sundance A, B, C, and Sheerness in late 2016, and confirmed the termination of the Keephills PPA in late 2017. For those Alberta PPAs that were terminated, the Balancing Pool had assumed the role of buyer. On Sep. 18, 2017, the Balancing Pool elected to terminate the Sundance B PPA and Sundance C PPA effective on or before March 31, 2018. Pursuant to a written agreement, the Balancing Pool paid us approximately $157 million on March 29, 2018. We disputed the termination payment received as the Balancing Pool excluded certain mining and corporate assets that should have been included in
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the net book value calculation. On Aug. 26, 2019, we announced that we were successful in the arbitration and received the full amount claimed by us to have been owing, being $56 million, plus GST and interest. See "General Development of the Business - Three-Year History - Generation and Business Development."
Our hydroelectric facilities, other than Belly River, Pocaterra, St. Mary, Taylor and Waterton, were aggregated through one Alberta PPA that provides for financial obligations for energy and ancillary services based on hourly targets. We met these targeted amounts through physical delivery or third-party purchases.
The Alberta PPAs expired on Dec. 31, 2020 and these facilities are now merchant units in the Alberta power market.
Competitive Environment
Power generation is an industry in the midst of an exciting transformation and the demand for electricity is expected to grow significantly over the long-term. In addition to the need to keep pace with ongoing demand growth for electricity, there are several key factors driving the need for significant investment in new generating capacity going forward. First, coal-based generation is being retired. These retirements are being driven by asset age, as well as government policy that places a price on emissions and, in some cases, mandates the retirement of these assets. Second, government policies that impose costs or provide incentives for lower emission technologies are creating opportunities for renewable generation technologies. These opportunities are coinciding with a significant decline in the installed costs of both wind and solar generation. As a result, these technologies now account for the majority of the new generating capacity added to many of the world's electricity grids. Third, electrification is seen as a one of the most effective levers to reduce GHG emissions in many sectors such as transportation. As these sectors and others continue to shift to electricity as their primary energy source we will see accelerating demand growth for our product.
We expect that renewable power generation will be one of the fastest-growing sources of power generation in both Canada and the US, a forecast that is well supported by recent trends and announcements. We are ready for this transformation. We have the skills, experience and scale to compete for additional assets within our target markets. Today, we are one of the largest publicly traded renewable power generation companies in Canada.
Alberta
Alberta's annual demand contracted approximately 2.5 per cent from 2019 to 2020 due to the combined impacts of COVID-19 and oil production shut-ins. The drop in demand was most significant in the second and third quarters. The average pool price decreased from $55 per MWh in 2019 to $47 per MWh in 2020. Pool prices were lower in each quarter compared to 2019, with additional weakness during the second quarter as a result of higher power imports into Alberta.
Alberta's Fair, Efficient and Open Competition Regulation generally provides that an electricity market participant shall not control more than of 30 per cent of the total maximum capability of generating units in Alberta. A market participant’s total offer control is measured as the ratio of MW under its control, to the sum of maximum capability of generating units in Alberta. Our market share of offer control in Alberta in 2020 was approximately 21 per cent (16 per cent if the Sundance mothballed units are excluded from offer control).
In November 2016, we announced that we had entered into an Off-Coal Agreement with the Government of Alberta that provides transition payments from the Government in consideration for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired facilities on or before Dec. 31, 2030. The affected facilities are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. We also entered into a Memorandum of Understanding with the Government of Alberta to collaborate and co-operate in the development of a market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation.
US Pacific Northwest
Our capacity in the US Pacific Northwest is represented by our 1,340 MW Centralia coal facility which declined to 670 MW as of Jan. 1, 2021. In the fourth quarter of 2020, we added a 49 per cent interest in the Skookumchuck wind facility. The Centralia coal facility is committed to be phased-out over the next five years, with the remaining plant capacity scheduled to retire at the end of 2025.
System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited and further constrained by an emphasis on energy efficiency. We expect to see significant change in this market over the next decade as coal generation is retired and renewable portfolio standard requirements continue to strengthen.
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Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the Centralia facility. The contract and our hedges allow us to satisfy power requirements from the market during low-priced periods.
We maintain the right to redevelop Centralia as a gas facility after coal capacity retires, with an opportunity for expedited permitting provided for in our agreement for coal transition established with the State of Washington in 2011.
Contracted Gas and Renewables
The market for developing or acquiring gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with TransAlta Renewables. In the U.S., our substantial tax attributes further increase our competitiveness.
While depressed commodity prices have reduced sectoral growth in the oil, gas and mining industries, the change is also creating opportunities for us as a service-provider as some of our potential customers are more carefully evaluating non-core activities and seeking operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in Western Canada and the United States along with targeted acquisitions in these same markets. We maintain highly qualified and experienced development teams to identify and develop these opportunities. In cogeneration, we are working with customers to evaluate behind-the-fence solutions.
Some of our older gas facilities are now reaching the end of their original contract life. The facilities generally have a substantial cost advantage over new builds and we have been able to add value by recontracting these facilities with limited life-extending capital expenditures. We have recently extended the contracted life of our Ottawa (2033 expiry), Windsor (2031 expiry), Parkeston (2026 expiry), Fort Saskatchewan (2030 expiry) and Southern Cross Energy (2038) facilities in this manner.
Australia
The Australian electricity industry is divided among three distinct markets, the National Electricity Market (NEM) in the East, the Wholesale Electricity Market (WEM) in Western Australia and the Northern Territory Electricity Market. In addition, there is a significant market for "off-grid" generation supporting remote communities and remote mining operations, particularly in Western Australia, Queensland and the Northern Territory.
The NEM is the largest market in Australia, currently with over 53 GW of installed capacity. The installed capacity based on coal generation is about 23 GW and much of this is expected to retire over the next decade due to the age of these assets. Renewables penetration, both wind and solar, has grown strongly in this market and that is expected to continue. The federal Department of Environment and Energy predicts an overall renewables penetration of 50 per cent in the NEM and 55 per cent in the WEM by 2030.
Our business today is solely in Western Australia, and focused on the large remote mining industry in that state. The primary exports from Western Australia are iron ore, nickel and gold and these three industries are all performing well. Commodity prices are strong, especially iron ore. Iron ore exports from Western Australia are forecast to rise driven by large-scale producers ramping up production with new mines. The nickel industry is also experiencing an increase in demand to support both steel and battery manufacturers. Remote mining operations are exploring options to add renewable generation to their existing and new sites in an effort to reduce the amount of gas and diesel required in these operations. Our Southern Cross Energy facilities in the Goldfields region has a number of projects in development under our newly extended contractual arrangement to help our customer achieve their decarbonization objective. We expect this trend to continue and to create further opportunities for our business in Western Australia.
Seasonality and Cyclicality
Our business cyclical, particularly in respect of the renewables generation held by TransAlta Renewables, due to: (a) the nature of electricity and the limited storage capacity; and (b) the nature of wind, solar and run-of-river hydroelectric resources, which fluctuate based on both seasonal patterns and annual weather variation.
Typically, run-of-river hydroelectric facilities and solar facilities generate most of their electricity and revenues during the spring and summer months when the melting snow starts feeding the watersheds and the rivers, and the sun is at its highest peak. Inversely, wind speeds are historically greater during the cold winter months when the air density is at its peak. TransAlta Renewables’ strategy of technological and geographical diversification reduces the Corporation’s exposure to the variations of any one natural resource in any one region. Since TransAlta Renewables’ operations are presently based mainly on power generation from wind, its financial results in any one quarter may not, however, be representative of all quarters. See "Risk Factors."
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Regulatory Framework
Below is a description of the regulatory framework in the markets that are material to the Corporation.
Canadian Federal Government
In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030, following a similar commitment by the Alberta provincial government in November 2015. These decisions changed the coal facility closure requirements, which had previously been guided by federal regulations that became effective on July 1, 2015, which provided for up to 50 years of life for coal units. On Feb. 16, 2018, Environment and Climate Change Canada announced draft regulations to phase out coal-fired generation by 2030, as well as draft regulations for gas-fired electricity generation including provisions for the conversion of boiler units from coal-fired generation to natural-gas fired generation. Please refer to "Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation" for more information.
Alberta
Since Jan. 1, 1996, new generating capacity initiatives in Alberta have been undertaken by independent power producers ("IPP") and have been subject to market forces, rather than rate regulation. Power from commercial generation is cleared through a wholesale electricity market. Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power. The Market Surveillance Administrator for the Province of Alberta is an independent entity responsible for monitoring and investigating the market behaviour of market participants, including the AESO and the Balancing Pool, and enforcing compliance with all applicable legislation, regulations, AESO and AUC rules. The AUC oversees electricity industry matters, including new power plant and transmission facilities and the distribution and sale of electricity and retail natural gas. The AUC is also responsible for approving the AESO's rules and for determining penalties and sanctions on any participant found to have contravened market rules.
On July 24, 2019, the Government of Alberta announced that it will not transition to a capacity market and will continue with an energy-only market design. This decision stopped all work on the capacity market design work, which had been underway through the AESO since 2017. The Government’s announcement followed a stakeholder consultation and review that found stakeholder support for maintaining the energy-only market based upon its proven track record for providing a reliable supply and affordable electricity for Albertans. The removal of legislative changes to enable the capacity market received royal assent on Oct. 31, 2019.
The Minister of Energy further directed Alberta Energy to conduct a policy review on market power and market power mitigation in the energy-only and ancillary services market and directed the AESO to conduct analysis and make recommendations on whether changes are needed to the price floor/ceiling and shortage pricing by July 31, 2020. The AESO's review concluded that no changes were necessary to the pricing or market power mitigation framework in the energy-only market. On Aug. 28, 2020, the Associate Minister announced that the government accepts the AESO's recommendation and no changes will be made to Alberta's energy-only wholesale market design.
Ontario
Ontario's electricity market is a hybrid market that includes a wholesale spot electricity market, as well as regulated prices for certain electricity consumers and long-term contracts for the purchase of power by the IESO from power producers. The IESO is the successor organization resulting from the merger of the former IESO and Ontario Power Authority in 2015. The Ontario Ministry of Energy, Northern Development and Mines supports the IESO in defining the electricity mix to be procured by the IESO. The IESO has the mandate to undertake long-term planning of the electric power system, procure the electricity generation in that plan and manage contracts for privately owned generation. The IESO is responsible for managing the Ontario wholesale market and for ensuring the reliability of the electricity system in Ontario. The electricity sector is regulated by the Ontario Energy Board.
The IESO began a market renewal consultation that includes proposed fundamental changes to the electricity market. These include modifying the energy market, adding a capacity market and improving operability and reliability. The IESO ran its first capacity auction in December 2020. The IESO has also begun developing a resource adequacy framework that it intends to develop in 2021. The IESO is continuing to consult on changes to the energy market that are expected to be implemented in early 2023.
British Columbia
British Columbia's electricity market is dominated by BC Hydro, a vertically integrated Crown corporation. The other provincial utility, FortisBC, has a small service territory in the interior of the province. Electricity is traded with other markets through BC Hydro's trading arm and wholly-owned subsidiary, Powerex. All electricity utilities are regulated by the British Columbia Utilities Commission ("BCUC").
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Under government direction in the late 1990s and early 2000s, BC Hydro established a private power market through several competitive calls for power from IPPs. In recent years, BC Hydro stopped its competitive power calls and contracting with IPPs and also suspended its smaller Standing Offer Program for small projects below 15 MW.
BC Hydro is delaying discussions related to recontracting assets until it has completed it new Integrated Resource Plan ("IRP"). In 2020, BC Hydro started its Clean Power 2040 consultation process to feed into the development of IRP . The purpose of the Clean Power 2040 is to develop a long-term electricity system view to meet the climate change and supply objectives related to provincial policy and legislation. The first round of discussions were completed in late 2020. In early Spring 2021, a second round of consultations will take place on the draft IRP that was developed based on the findings of the round one discussions. BC Hydro expects to submit its final IRP to the BCUC in September 2021. The BCUC will hold a public review process on the IRP prior to providing a decision on the IRP.
Current Clean Power 2040 initial results indicate BC Hydro continues to find a need to renew Energy Purchase Agreements with existing independent power producers, which could include TransAlta's Pingston Hydro project.
Québec
The Régie de l'énergie is Québec's regulatory authority with primary jurisdiction over the economic regulation of the electricity sector. Québec is served principally by Hydro-Québec, a government-owned entity with highly-competitive hydroelectric resources. It has an almost exclusive right to distribute electricity throughout the Province of Québec. Most of Hydro-Québec's generation stations are located substantial distances from consumer centres. As a result, Québec's transmission system is one of the most extensive and comprehensive in North America, comprising more than 33,000 kilometres of lines. In all cases, an agreement with Hydro-Québec on the price of the electricity produced is required before a project can obtain governmental approval. Overall, Hydro-Québec's structure makes new projects difficult but existing projects, such as Le Nordais, that have contracts in place are generally unaffected and are able to re-contract.
New Brunswick
In 2004, New Brunswick enacted the Electricity Act (New Brunswick), under which the province's electricity market changed to enable the creation of a competitive environment for eligible wholesale, industrial and municipal utility customers. The legislation provides that, as generating assets are retired or as additional supply is required, standard service suppliers (i.e. the distribution companies) will procure new supply through the competitive market. This means that any new resources required by New Brunswick Power will be acquired through procurement processes open to both IPPs, as well as the New Brunswick Power.
US Wholesale Power Market
The Federal Power Ac t gives the Federal Energy Regulatory Commission ("FERC") rate-making jurisdiction over public utilities engaged in wholesale sales of electricity and the transmission of electricity in interstate commerce. The Federal Power Act also provides FERC with the authority to certify and oversee an electric reliability organization that promulgates and enforces mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified the North American Electric Reliability Corporation ("NERC") as the electric reliability organization. NERC has promulgated mandatory reliability standards, and, in conjunction with the regional reliability organizations that operate under FERC's and NERC's authority and oversight, enforces those mandatory reliability standards.
Minnesota (MISO)
Lakeswind in Minnesota is connected to the Midwest Independent System Operator (MISO) and falls under FERC jurisdiction. FERC-approved MISO tariffs dictate market and operational requirement for facilities. MISO has both an energy market and a voluntary capacity market. Under the long-term contract, all power is delivered at the plant-gate, ensuring market changes should have an immaterial impact on revenues.
Massachusetts (NE-ISO)
The Mass Solar facility is connected to the distribution grid so its generated electricity flows directly to the utility and is not offered into the integrated market. All revenues associated with this project flow from the State's net metering and Renewable Energy Portfolio Standard programs. Market changes are not expected to have a material impact on net metering revenues.
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New Hampshire (NE-ISO)
Antrim in New Hampshire is connected to the New England Independent System Operator (NE-ISO) and falls under FERC jurisdiction. FERC-approved NE-ISO tariffs dictate market and operational requirements for facilities. The NE-ISO has both an energy and a mandatory-participation capacity market. Antrim's electricity is offered into the market and transferred to the buyers. Antrim has a long-term capacity supply obligation so it is not impacted by near term changes to the capacity market auction process. As Antrim and most other intermittent wind projects must take part in the NE-ISO's Do Not Exceed Dispatch, market changes are not expected to have a material impact on revenues.
Pennsylvania (PJM)
Big Level in Pennsylvania is connected to the PJM ISO and falls under FERC jurisdiction. FERC-approved PJM tariffs dictate market and operational requirements for facilities. PJM has both an energy and a mandatory participation capacity market. Big Level's attributes including energy, capacity, and environmental credits have been transferred to the buyer. As a result, market changes are not expected to have a material impact on revenues during the contract term.
Washington
The Washington Transportation and Utilities Commission has the power to regulate and supervise every "public utility," which includes investor-owned electric utilities. For regulated electric utilities, the commission approves regulated rates, reviews integrated resource plans, approves mergers and acquisitions and grants certificates of public convenience and necessity for large facilities (i.e. power plants and transmission lines). Centralia and the Skookumchuck wind facility are not regulated by the Commission as they only sell wholesale electricity and do not sell retail electricity in the state. Only FERC and NERC requirements apply to the facility. As a result, the Corporation does not expect any material impacts on revenue streams from any commission decisions.
Wyoming
The Wyoming Public Service Commission has the power to regulate and supervise every "public utility," which includes the four investor-owned electric utilities in Wyoming, as well as certain natural gas, electric, telecommunications, water and pipeline services. For regulated electric utilities, the commission approves regulated rates, reviews integrated resource plans, approves mergers and acquisitions and grants certificates of public convenience and necessity for large facilities (i.e., power plants and transmission lines). Wyoming wind facility is not regulated by the commission as it only sells wholesale electricity and does not sell retail electricity in the state. Only FERC and NERC requirements apply to the facility. As a result, the Corporation does not expect any material impact on revenue streams from any commission decisions.
Australia
Australia has two separate major electricity markets, the NEM encompassing all the major population centres on the Eastern seaboard, and the WEM covering the southwest of Western Australia including its capital city, Perth. A number of smaller, standalone electricity grids serve regional population centres including the North West Interconnected System ("NWIS") in the Pilbara region of Western Australia and the Darwin-Katherine System in the Northern Territory.
The Australian Energy Market Operator is the market operator for both the WEM and the NEM. The two markets are completely independent of each other having different market rules and no physical interconnection between them. The WEM includes both a market for generation capacity and a gross pool to trade energy with a single reference node for wholesale prices. The NEM is a pure energy-only market with five regional reference nodes for wholesale prices corresponding to each of the participating states of Queensland, New South Wales, Victoria, Tasmania and South Australia.
The Public Utilities Office of Western Australia ("PUO") in its capacity as advisor to the Minister for Energy is currently working with Australian Energy Market Operator and the wider electricity industry to implement further reforms to the WEM including introducing constrained network access and required consequential amendments to the wholesale market rules to allow for security constrained dispatch. A comprehensive program of works is currently underway with a goal of implementing reforms on Oct. 1, 2022.
The PUO is also working with participants in the NWIS to introduce some elements of a more formal electricity market, including providing third-party access to the Horizon Power-owned part of the NWIS and providing centralized coordination of dispatch and ancillary services.
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Competitive Strengths
We believe that we are well positioned to achieve our business strategy due to our competitive strengths, which include the following:
Operating Strength
We continually benchmark ourselves against previous year performance in order to drive operating costs lower year over year, while also maintaining strong levels of generation performance. We have implemented a program to drive incremental value from our fleet by developing initiatives to improve generating equipment efficiencies, refining processes and procedures, and optimizing cost structures. Our Sarnia cogeneration facility has demonstrated industry best practices through several operations and maintenance processes, including the work management process and Environmental, Health & Safety scorecard. We believe the continued maturity of these programs will continue to drive further value in the operations of our facilities.
Stable Cash Flow Base
Through the use of long-term contracts, approximately 47 per cent of our capacity is contracted in 2021 and 2022. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity. The Corporation also regularly hedges portions of its uncontracted merchant positions to further stabilize cash flows from market volatility.
Portfolio Diversity
The diversity of our fuel sources used for the generation of electricity underscores our desire to be Canada's leading clean electricity supplier. Our portfolio mix consists of wind, hydro, solar, energy storage, and natural gas. In 2020, we successfully commissioned Alberta's first utility-scale battery storage project that is powered by the Summerview 2 wind facility.
We continue to use coal as a source of fuel during our transition at a number of our facilities and we optimize this fuel through co-firing with natural gas to produce cleaner and lower cost electricity. We will continue to optimize this strategy until we fully complete the transition off coal to natural gas at our Alberta Thermal facilities by the end of 2021.
We believe we have reduced the potential impact of external events that affects one fuel source or one geographic region on our performance given the location of our operations across Canada, the United States and Australia, as well as our diverse fuel mix.
Management Team and Employee Experience
Our management team has substantial industry, international, investment and market experience. The experience and acumen of our employees further enhances our capital value creation. Our business has been operating for more than 109 years, and many of our employees have been with us for more than 30 years.
Energy Marketing Expertise
We believe that our Energy Marketing segment has enhanced returns from our existing generation base and has allowed us to obtain more favourable pricing for uncommitted electricity, secure fuel supply on a cost-effective basis and fulfill electricity delivery obligations in the event of an outage.
Wind Generation
Through our ownership interest in TransAlta Renewables, we are one of the largest owners and operators of wind generation in Canada. Our management team has developed key relationships with customers, suppliers and policy makers that provide a competitive advantage in the development, operations and marketing of wind generation.
Environmental, Social and Governance
We are a recognized leader in sustainable development and we have taken early preventive action on a number of environmental fronts in advance of regulation. We have a long history of adopting leading sustainability practices, including 25 years of sustainability reporting and voluntarily integrating our sustainability report into our annual report. We have been issuing an integrated annual report since 2015. We test our practices and our reporting against standards set by CDP (formerly the Carbon Disclosure Project), the Task Force on Climate-related Financial Disclosures and the Canadian Council for Aboriginal Business. TransAlta has been operating hydroelectric facilities for more than 109 years and was an early adopter of wind power generation, acquiring its first wind assets in 2002. Today we are the leading producer of wind power in Canada. Through our ongoing transformational efforts and largely through our coal transition, we are on track to reduce our total GHG emissions by approximately 70 per cent from 2005 levels by the end of 2022.
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Environmental Risk Management
We are subject to federal, provincial, state and local environmental laws, regulations and guidelines concerning the generation and transmission of electrical and thermal energy and surface mining. We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations. We work with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.
Ongoing and Recently Passed Environmental Legislation
Changes in current environmental legislation do have, and will continue to have, an impact on our operations and business. For further details, see below and "Risk Factors."
Climate-Related Financial Disclosure
TransAlta has prepared an assessment of climate-related risks and opportunities to conform with the recommendations of the Task Force on Climate-related Financial Disclosure describing our climate change strategy, governance, risk management approach, GHG metrics and targets. This document can be accessed on our website at www.transalta.com/sustainability/reporting-our-sustainable-value.
Canadian Federal Government
Federal Carbon Pricing on GHG
On June 21, 2018, the Canadian federal Greenhouse Gas Pollution Pricing Act ("GGPPA") came into force. Under the GGPPA, the Canadian federal government implemented a national price on GHG emissions. The price began at $20 per tonne of CO 2 e emissions in 2019, and rises by $10 per year until reaching $50 per tonne in 2022. In 2022, there will be a review of the Output-Based Pricing Standard ("OBPS") and other aspects of the GGPPA.
The OBPS regulates large emitters' carbon intensity by setting a sectoral performance standard (benchmark) of GHG emissions per unit of production. Emitters exceeding the benchmark generate carbon obligations and those emitters that perform below the benchmark generate EPCs. Emitters can meet their obligations by reducing their emission intensity, buying carbon credits from others (offsets or EPCs) or making compliance payments to the government.
On Jan. 1, 2019, the GGPPA's backstop mechanisms came into force in provinces and territories that did not have an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system. The backstop mechanism has two components: the federal pollution pricing fuel charge ("Carbon Tax") and the regulation for large emitters, OBPS. The Carbon Tax sets a carbon price per tonne of GHG emissions related to transportation fuels, heating fuels and other small emission sources. As noted below, Ontario is the only jurisdiction where TransAlta operates assets covered by the OBPS and this will change as the province initiates its own emissions regulation for large emitters. Alberta and Ontario are subject to the federal Carbon Tax.
Other jurisdictions that were compliant with the GGPPA did not have the backstop mechanism imposed in 2020. These jurisdictions must file and have their carbon pricing programs approved annually by the federal government. Over future annual compliance periods, if parts or all of a province's GHG regulations fall out of compliance with the GGPPA, the federal government will impose its backstop mechanisms.
In Reference re Greenhouse Gas Pollution Pricing Act, the Court of Appeal of Alberta held that Parts 1 and 2 of the GGPPA are unconstitutional in their entirety. This decision is the first time that a court has found the GGPPA to be unconstitutional. In split decisions released last year, both the Court of Appeal for Ontario and the Court of Appeal for Saskatchewan concluded that the GGPPA is constitutional. The Supreme Court of Canada is set to determine the matter in 2021.
On Dec. 11, 2020, the Government of Canada released its “A Healthy Environment and a Healthy Economy” climate plan that outlines how the federal government intends to use policies, regulations, and funding to achieve Canada’s Paris Agreement emissions reduction target of a 30 per cent reduction from 2005 GHG emission levels. The three major aspects of the plan include increased carbon prices and obligations, increased funding for clean technology and the implementation of the Clean Fuel Regulation (“CFR”). The government stated that it will consult with provinces and industry regarding many elements of the plan so significant uncertainty remains regarding final form of the regulations and other initiatives.
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The following are key proposed elements of the federal plan:
•The carbon price for the carbon tax and the larger emitters program will rise $15 per tonne CO 2 e per year from 2023 until reaching $170 per tonne CO 2 e by 2030;
•Carbon obligations will rise as benchmark under large emitter regulations tighten;
•Over $10 billion of funding will be available for everything from electric vehicles and clean energy development, to battery storage and improved grid technology; and
•The CFR will apply to liquid fuels but not to gaseous and solid fuels.
TransAlta will continue to engage with governments to mitigate risks and identify opportunities within the new federal plan.
Gas Regulation
On Dec. 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. Under the regulations, new and significantly modified natural-gas fired electricity facilities with a capacity greater than 150 MW must meet a standard of 0.420 tonnes of CO 2 e/MWh to operate. For units with a capacity between 25 MW and 150 MW , their standard was set at 0.550 tCO 2 e/MWh. For units of 25 MW or less, there is no standard.
Under the regulations, conversion to gas will also eventually have to meet a standard of 0.420 tonnes of CO 2 e/MWh. If the first -year performance test after conversion meets certain emission standards it will not have to meet the 0.420 tonnes of CO 2 e/MWh standard for several additional years past the end of its useful life.
Under the Healthy Environment and a Healthy Economy plan, the federal government signaled consideration of a new electricity emissions standard. TransAlta is engaging the federal government to understand the proposal.
Coal Regulation
On Dec. 12, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations came into force under the Canadian Environmental Protection Act, 1999. Under the amended regulations, coal units must meet an emission level of 0.420 tonnes of CO 2 e/MWh by the earlier of end-of-life or Dec. 31, 2029.
Clean Fuel Regulation
In 2016, the Canadian federal government announced plans to consult on the development of a CFR to reduce Canada’s GHG emissions through the increased use of lower carbon fuels, energy sources and technologies. The objective of the regulation is to achieve 30 million metric tonnes of annual reductions in GHG emissions by 2030.
On Dec. 19, 2020, the Canadian federal government published its draft version of the CFR with the accompanying supporting documents. As a result of gaseous fuels no longer being regulated by the CFR, the CFR will have a limited impact on the electricity sector. Consultation on the regulation will conclude on March 4, 2021. The CFR is scheduled to be finalized in December 2021 and come into force on Dec. 1, 2022.
Alberta
Large Emitter Greenhouse Gas Regulations
On Jan. 1, 2020, the Government of Alberta replaced the previous Carbon Competitiveness Incentive Regulation (CCIR) with a new regulation called the Technology Innovation and Emissions Reduction (TIER) regulation. For the electricity sector, there were negligible changes between CCIR and TIER with renewable facilities continuing to receive crediting. The carbon price for TIER in 2021 is $40 per tonne of CO 2 e aligned with the GGPPA requirements. The performance standard benchmark remained at 0.370 tonnes of CO 2 e/MWh. A review of TIER is not expected until 2023.
Facilities with emissions above the set benchmark comply with TIER by: a) paying into the TIER Fund (a government-controlled fund that invests in emissions reduction in the province) at the current carbon price; b) making reductions at their facility;c) remitting emission performance credits from other facilities; or iv) remitting emission offset credits.
As required by the GGPPA, the Alberta government files annual reports on TIER program details with the federal government. The federal government reviewed TIER and found it compliant with the GGPPA for 2021. The Company will continue to receive offsets and EPC for its renewable facilities under TIER ensuring expected revenues are realized.
British Columbia
Beginning April 1, 2018, the British Columbia government increased its carbon tax price to $35 per tonne of CO 2 e and committed to raise the price $5 per year until it reaches $50 per tonne in 2021. Upon review, the government has determined that the carbon tax rate will remain at its current level of $40 per tonne of CO2e until April 2021, when it
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will increase from $40 to $45 per tonne of CO2e. The carbon tax will increase to $50 per tonne of CO2e in April 2022. The tax has a negligible cost impact for the Company as the tax applies primarily to our transportation fuel use which is negligible in B.C.
Ontario
Large Emitter Greenhouse Gas Regulations
On July 4, 2019, the Government of Ontario released its own final regulations for the provincial Greenhouse Gas Emissions Performance Standards (EPS). On Sep. 21, 2020, the federal government accepted the Ontario government's EPS as meeting the requirements of the GGPPA. In Dec. 2020, the Ontario government published amendments to align the EPS with the GGPPA requirements. The Ontario government also announced its intention to transition from the OBPS to the EPS starting on Jan. 1, 2021. This mean Ontario's large emitters will have been covered by the OBPS for 2019 and 2020 compliance years and, in the future, will be covered by the EPS.
This requires TransAlta's Ontario natural gas fired assets to track and make compliance filings annually and to meet the carbon emission obligations of the applicable government. There are minor differences between the EPS and OBPS. Compliance requirements will be met through payments and alternative compliance units under the OBPS and EPS. However, change of law provisions in the contracts with Sarnia, Windsor and Ottawa allow TransAlta to flow carbon regulation-related costs to customers, resulting in negligible cost increases to the Company.
Massachusetts
The Solar Renewable Electricity Credit I (SREC I) program carved out from Massachusetts’ Renewable Portfolio Standard (RPS) an initial quantity of 400 MW from small solar facilities of 10 MW or less. The initial SREC I program size was expanded then replaced by a lower valued SREC II program. In 2018, the solar incentive program evolved into the current Solar Massachusetts Renewable Target program that further reduced the incentive levels.
The initial SREC I program’s volume target was achieved, and qualified projects under SREC I continue to generate SREC I credits for their first 10 years following their commercial operations date. SREC I facilities then generate Class 1 RECs under the Massachusetts RPS for the remainder of their operational life.
Under Massachusetts' net metering program, qualified facilities connect with the local utility and generate net metering credits. Net metering credits offset the delivery, supply and customer charges and can be sold to customers from remote or on-site qualifying facilities. In 2016, the net metering program was updated to reduce the value of the net metering credits by reducing the offset to only energy costs. New projects are impacted once the net metering program volume reaches 1,600 MW. Existing facilities were grandfathered and continue to receive the full, original cost offset treatment for a period of 25 years from initial commercial operations date.
Le Nordais receives value from the sale of RECs into the New England RPS markets. Massachusetts has proposed a lower compliance cost ceiling on its RPS standard that would effectively cap the value of RECs. This could have a negative impact on Le Nordais' REC sales price. The change in regulation is still being considered and has not yet been put into force.
Minnesota (MISO)
Minnesota has a Renewable Portfolio Standard ("RPS") and allows Michigan RECs to be used by utilities and non-utilities to meet the requirement. The RECs generated by the Lakeswind wind facility have been sold to the customer as part of their long-term contract.
New Hampshire (ISO-NE)
The New Hampshire market has an RPS, is part of the New England REC market and is also a partner in the Regional Greenhouse Gas Initiative - a carbon cap and trade program. The Antrim wind facility has long-term contracts in place for its energy and environmental attributes plus long-term capacity commitments. As a result, state and regional environmental and market regulations and policy will have an immaterial impact on revenues.
Pennsylvania (PJM)
Pennsylvania has an RPS and is linked to the New England REC markets. In December 2019, FERC released an order directing PJM, the electric grid operator covering 13 states plus the District of Columbia, to significantly expand its minimum offer price rule (MOPR) to mitigate the impacts of state-subsidized resources on the capacity market. Under these new rules, PJM must establish resource-specific MOPRs for new and existing resources that receive (or are eligible to receive) state subsidies, including renewable energy credits used to promote renewable energy and zero-emission credit. The Big Level wind facility is exempt from the MOPR rule because its interconnection construction agreement was filed prior to Dec. 19, 2019.
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Washington
In 2010, the Washington Governor's office and department of Ecology negotiated agreements with TransAlta related to the operation of Centralia’s two coal power electricity generating units. TransAlta agreed to retire its two Centralia coal units: one in 2020 and the other in 2025. This agreement is formally part of the state’s climate change program. We currently believe that there will be no additional GHG regulatory burden on Centralia given these commitments. The related TransAlta Energy Transition Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation in the State of Washington.
If the state implements a carbon pricing regulation, the Transition Bill requires the state to exempt Centralia from any related costs.
Wyoming
Wyoming has no RPS or carbon-related market. No recent actions have been taken to reconsider a wind tax in the state. The Wyoming wind facility has long-term contracts for its power and environmental attributes and the Corporation expects state environmental and market regulations and policy will not have a material impact on revenues.
Australia
On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF"). The AU$2.55-billion ERF is the centrepiece of the Australian government's policy and provides a policy framework to cut emissions by five per cent below 2000 levels by 2020 and 26 to 28 per cent below 2005 emissions by 2030. The ERF's safeguard mechanism, commenced on July 1, 2016, is designed to ensure emissions reductions purchased by the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy.
In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET") scheme. The RET is designed to add at least 33,000 GWh per year of renewable sources by 2020. The Australian government has advised there are now sufficient projects approved to meet and exceed the 2020 target of 33,000 GWh/year of additional renewable electricity. The annual target will remain at 33,000 gigawatt hours until the scheme ends in 2030. This would result in approximately 23.5 per cent of Australia's electricity generation being sourced from renewable projects.
The ERF is not expected to have a material impact on our Australian assets. In Australia, electricity has a single sectoral baseline applied to all electricity generators' emissions for units connected to one of Australia's five main electricity grids. The electricity sector baseline has been set at 198 million tonnes CO2e per year. In the most recent high emission years 2015-2016, the total emissions were 179 million tonnes of CO2e per year.
If the baseline is exceeded, then all large emitter generation facilities will need to comply with individual facility baselines. The electricity sector should never exceed the sectoral emission target as no new coal generation is to be built and older coal facilities are retiring. The Company's gas facilities will not be subject to carbon costs under current regulations unless changes are made.
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TransAlta Activities
Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but to the communities in which we operate. We expect that increased scrutiny will continue to be placed on environmental emissions and compliance. We, therefore, take a proactive approach to minimizing risks to our results. Our Board provides oversight to our environmental management programs and emission reduction initiatives in order to ensure continued compliance with environmental regulations.
Our environmental management programs include the elements summarized below:
Environmental Management Systems
All our facilities have Environmental Management Systems (“EMS”) in place, the majority of which closely align with the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for over 20 years, and our systems and knowledge of management systems are therefore mature. Only two facilities do not have ISO 14001 aligned EMS in place, although these facilities do have a comparable EMS in place. This is due to commercial arrangements (TransAlta is not the operator of those two sites). Aligning with ISO 14001 provides assurance that our systems are designed to continuously improve performance.
Renewable Power
We continue to invest in and build renewable power resources. In 2020, we completed the purchase of a 49 per cent stake in the Skookumchuck wind facility in Washington State, which has a capacity of 137 MW. We also completed the development of an innovative 10 MW utility-scale battery storage project in Alberta, WindCharger, with support from Emissions Reduction Alberta. The battery storage project is the first of its kind in Alberta and is located at our Summerview 2 wind facility in southern Alberta.
In 2019, we brought into service two wind facilities located in the US totalling 119 MW. We are presently constructing an additional 207 MW of wind generation in Alberta. See "General Development of the Business – Three-Year History - Generation and Business Development."
We believe that a larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through environmental attributes (RECs or through emission offsets). In addition, we have developed policies and procedures to comply with regulatory guidance and to lessen any environmental disruption caused by our renewable power resources, which includes monitoring noise and the avian impacts at our wind generation facilities
Environmental Controls and Efficiency
We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. In 2020, we retired our Sundance 3 coal unit, which significantly reduces the environmental impacts associated with its generation. We have also converted our Sundance 6 coal unit to gas generation. We also announced our plan to discontinue coal-mining operations in Canada by Dec. 31, 2021. Effective Jan. 1, 2022, we will also discontinue firing coal in Canada with our operated assets. The combination will significantly reduce environmental impacts from air emissions, GHG emissions, water usage and land disturbance. Our planned conversions to gas and Sundance 5 repowering will reduce energy usage, GHG emissions and air emissions at the respective facilities. In addition, we acquired a 30 per cent interest in EMG International LLC. EMG has developed an innovative proprietary wastewater treatment system that provides breakthrough technological improvement in biological wastewater treatment.
Offsets Portfolio
TransAlta maintains a GHG emissions offset portfolio with a variety of instruments that can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet emission targets at a competitive cost. We ensure that any investments in offsets will meet certification criteria in the market in which they are to be used.
Environmental Regulations
Recent or future changes to environmental laws or regulations may materially adversely affect us. As indicated under "Risk Factors" in this AIF and within the "Governance and Risk Management" section of the Annual MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities and obligations under these requirements, which may have a material adverse effect upon our consolidated financial results, operations or performance.
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Risk Factors
Readers should consider carefully the risk factors set forth below as well as the other information contained and incorporated by reference in this AIF. For a further discussion of risk factors affecting TransAlta, please refer to "Governance and Risk Management" in the Annual MD&A, which is incorporated by reference herein.
A reference herein to a material adverse effect on the Corporation means such an effect on the Corporation or its business, financial condition, results of operations, or cash flows, as the context requires.
The operation and maintenance of our facilities involves risks that may materially and adversely affect our business.
The operation, maintenance, refurbishment, construction and expansion of power generation facilities involve risks, including breakdown or failure of equipment or processes, fuel interruption and performance below expected levels of output or efficiency. Some of our generation facilities, particularly in Alberta, were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or to maintain operations. There can be no assurance that our maintenance program will be able to detect potential failures in our facilities before they occur or eliminate all adverse consequences in the event of failure. In addition, weather-related interference, work stoppages and other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect us.
We have entered into ongoing maintenance and service agreements with the manufacturers of certain critical equipment. If a manufacturer is unable or unwilling to provide satisfactory maintenance or warranty support, we may have to enter into alternative arrangements with other providers if they cannot perform the maintenance themselves. These arrangements could be more expensive to us than our current arrangements and this increased expense could have a material adverse effect on our business. If we are unable to enter into satisfactory alternative arrangements, our inability to access technical expertise or parts could have a material adverse effect on us.
While we maintain an inventory of, or otherwise make arrangements to obtain, spare parts to replace critical equipment and maintain insurance for property damage to protect against certain operating risks, these protections may not be adequate to cover lost revenues or increased expenses and penalties that could result if we were unable to operate our generation facilities at a level necessary to comply with sales contracts.
We may be subject to the risk that it is necessary to operate a facility at a capacity level beyond that which we have contracted for power in order to provide steam in fulfillment of such a contract. In such circumstances, the costs to produce the steam being sold may exceed the revenues derived therefrom.
Unexpected changes in the cost of maintenance or in the cost and durability of components for the Corporation's facilities may adversely affect its results of operations.
Unexpected increases in the Corporation's cost structure that are beyond the control of the Corporation could materially adversely impact its financial performance. Examples of such costs include, but are not limited to, unexpected increases in the cost of procuring materials and services required for maintenance activities, and unexpected replacement or repair costs associated with equipment underperformance or lower-than-anticipated durability.
Equipment failure may cause us to suffer a material adverse effect.
There is a risk of equipment failure material to our operations due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on our business. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, and other issues that can lead to outages and increased production risk. An extended outage could have a material adverse effect on our business, financial condition or cash flow from operations.
There can be no assurance that any applicable insurance coverage would be adequate to protect our business from material adverse effect. In addition, there can be no assurance that we will be able to restore equipment or assets that have reached the end of their useful life.
The impact of COVID-19 could have an adverse impact on the Corporation's construction projects and the operation and maintenance of our assets.
The impact of COVID-19 and the associated general economic downturn on the Corporation will largely depend on the overall severity and duration of such events, which cannot currently be predicted, and that present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability
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impacting our ability to continue to staff the Corporation’s operations and facilities; impacts on the Corporation’s ability to realize its growth goals; decreases in short-term and/or long-term electricity demand and lower power pricing; increased costs resulting from the Corporation’s efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets that could limit the Corporation’s ability to obtain external financing to fund its operations and growth expenditures; a higher rate of losses on accounts receivables due to credit defaults; disruptions to the Corporation’s supply chain; impairments and/or writedowns of assets; and adverse impacts on the Corporation’s information technology systems and the Corporation’s internal control systems as a result of the need to increase remote work arrangements, including increased cybersecurity threats.
Responses to the COVID-19 pandemic throughout North America have driven a reduction in demand for electricity as municipal, provincial and state authorities implemented social distancing policies, and stay-at-home and/or “shelter-in-place” directives. In turn, this put downward pressure on forward electricity prices. There is currently no certainty as to when the pandemic will be brought fully under control, but public expectations generally indicate that these impacts could continue well into 2021.
Our facilities, construction projects and operations are exposed to effects of natural disasters, public health crises and other catastrophic events beyond our control and such events could result in a material adverse effect.
Our facilities, construction projects and operations are exposed to potential interruption and damage, partial or full loss, resulting from environmental disasters (e.g. floods, high winds, fires, ice storms, earthquakes and public health crises, such as pandemics and epidemics), other seismic activity, equipment failures and the like. Climate change can increase the frequency and severity of these extreme weather events. There can be no assurance that in the event of an earthquake, hurricane, tornado, tsunami, typhoon, terrorist attack, act of war or other natural, man-made or technical catastrophe, all or some parts of our generation facilities and infrastructure systems will not be disrupted. The occurrence of a significant event that disrupts the ability of our power generation assets to produce or sell power for an extended period, including events that preclude existing customers under PPAs from purchasing electricity, could have a material negative impact on our business. Our facilities, construction projects and operations could be exposed to effects of severe weather conditions, natural and man-made disasters and potentially other catastrophic events. The occurrence of such an event may not release us from performing our obligations pursuant to PPAs or other agreements with third parties. In addition, many of our generation facilities are located in remote areas which make access for repair of damage difficult. Catastrophic events, including public health crises, could result in volatility and disruption to global supply chains, disruption to global financial markets, trade and market sentiment, risks to employee health and safety, a slowdown or temporary suspension of operations in impacted locations, postponements in the initiation and/or completion of the Corporation's development or construction projects, and delays in the completion of services, any of that may result in the Corporation incurring penalties under contracts, additional costs, or the cancellation of contracts.
We could suffer lost revenues or increased expenses and penalties if we are unable to operate our generation facilities at a level necessary to comply with our PPAs.
The ability of our facilities to generate the maximum amount of power that can be sold under PPAs is an important determinant of our revenues. Under certain PPAs, if the facility is not capable of generating electricity for the required availability in a given contract year, penalty payments may be payable to the relevant purchaser by us. The payment of any such penalties could adversely affect our revenues and profitability.
We are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if these relationships are not maintained.
Our ability to compete and expand will be dependent on having access, at a reasonable cost, to equipment, parts and components that are technologically and economically competitive with those used by our competitors. Although we have individual framework agreements with various suppliers, there can be no assurance that these relationships with suppliers will be maintained. If they are not maintained, our ability to compete may be impaired due to lack of access to these sources of equipment, parts or components.
We depend on certain joint venture, strategic and other partners that may have interests or objectives which conflict with our objectives and such differences could have a negative
impact on us.
We have entered into various arrangements with communities or joint venture, strategic or other partners in connection with the operation of our facilities and assets. Certain of these partners may have or develop interests or objectives that are different from, or in conflict with, our objectives. Any such differences could have a negative impact
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on the Corporation's ability to realize upon the anticipated benefits of, or the anticipated increase in the value of facilities or assets subject to, these arrangements. We are sometimes required through the permitting and approval process to notify and consult with various stakeholder groups, including landowners, First Nations and municipalities. Any unforeseen delays in this process may negatively impact our ability to complete any given facility on time or at all and could result in write-offs or give rise to reputational harm.
Dam and dyke failures may result in lost generating capacity, increased maintenance and repair costs and other liabilities.
A natural or man-made disaster, and certain other events, including natural or induced seismic activity, could potentially cause dam failures at our hydroelectric facilities. The occurrence of dam or dyke failures at any of our hydroelectric or coal facilities could result in a loss of generating capacity, damage to the environment or damages and harm to third parties or the public, and such failures could require us to incur significant expenditures of capital and other resources or expose us to significant liabilities for damages. There can be no assurance that our dam safety program will be able to detect potential dam failures prior to occurrence or eliminate all adverse consequences in the event of failure. Other safety regulations could change from time to time, potentially impacting our costs and operations. Reinforcing all dams or dykes to enable them to withstand more severe events could require us to incur significant expenditures of capital and other resources. The consequences of dam or dyke failures could have a material adverse effect on us.
The power generation industry has certain inherent risks related to worker health and safety and the environment that could cause us to suffer unanticipated expenditures or to incur fines, penalties or other consequences material to its business and operations.
The ownership and operation of our power generation assets carry an inherent risk of liability related to worker health and safety and the environment, including the risk of government-imposed orders to remedy unsafe conditions and/or to remediate or otherwise address environmental contamination, potential penalties for contravention of health, safety and environmental laws, licenses, permits and other approvals, and potential civil liability. Compliance with (and any future changes to) health, safety and environmental laws and the requirements of licenses, permits and other approvals are expected to remain material to our business. The occurrence of any of these events or any changes, additions to, or more rigorous enforcement of, health, safety and environmental laws, licenses, permits or other approvals could have a significant impact on our operations and/or result in additional material expenditures. As a consequence, no assurances can be given that additional environmental and workers' health and safety issues relating to presently known or unknown matters will not require unanticipated expenditures, or result in fines, penalties or other consequences (including changes to operations) material to our business and operations.
Climate change and other variations in weather can affect demand for electricity and our ability to generate electricity.
Due to the nature of our business, our earnings are sensitive to weather variations from period to period. Variations in winter weather affect the demand for electrical heating requirements. Variations in summer weather affect the demand for electrical cooling requirements. These variations in demand translate into spot market price volatility. Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight conditions can have an effect on energy production levels from our solar facility. Variations in weather may be impacted by climate change resulting in sustained higher temperatures and rising sea levels that could have an impact on our generating assets. In Western Australia and other operating locations, temperatures could periodically exceed certain operating and safety thresholds, which could make it difficult for the Corporation to continue to generate electricity for such periods, and such circumstances could pose threats to the Corporation's equipment and personnel.
Ice can accumulate on wind turbine blades in the winter months. The accumulation of ice on wind turbine blades depends on a number of factors, including temperature, and ambient humidity. The accumulation of ice on wind turbine blades can have a significant impact on energy yields, and could result in the wind turbine experiencing more down time. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production.
In addition, climate change could result in increased variability to our water and wind resources.
Many of our activities and properties are subject to environmental requirements and changes in, or liabilities under these requirements, may materially adversely affect our business.
Our operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines, relating to the generation and transmission of electrical and thermal energy and surface mining, pertaining to pollution and protection of the environment, health and safety, and governing, among other things, air emissions, water usage and discharges, storage, treatment and disposal of waste and other materials and remediation of sites and land use
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responsibility (collectively, "environmental regulations"). These laws can impose liability and obligations for costs to investigate and remediate contamination without regard to fault and under certain circumstances liability may be joint and several, resulting in one responsible party being held responsible for the entire obligation. Environmental regulation can also impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transport, treatment and disposal of hazardous substances and waste and can impose clean-up, disclosure or other responsibilities with respect to spills, releases and emissions of various substances to the environment. Environmental regulation can also require that facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, there is an increasing level of environmental regulation regarding the use, treatment and discharge of water and we anticipate the adoption of new or additional emission regulations at a national level in Canada, the US and Australia, which may impose different compliance requirements or standards on our business. These various compliance standards may result in additional costs for our business or may impact our ability to operate our facilities.
To comply with environmental regulations, we must incur material capital and operating expenditures relating to environmental monitoring, emissions and effluent control equipment and processes; emissions measurement, verification and reporting; emissions fees; and other compliance activities or obligations. We expect to continue to have environmental expenditures in the future. Stricter standards, new or greater regulation, increased enforcement by regulatory authorities, more extensive permitting requirements, an increase in the number and types of assets operated by the Corporation subject to environmental regulation and the implementation of provincial, state and national GHG emissions, mercury emissions or other air emissions regulation that in themselves may not be aligned and may impose varying obligations on us in the jurisdictions in which we operate and which could increase the amount of our expenditures. To the extent these expenditures cannot be passed through to our customers under our PPAs or otherwise, our costs could be material. In addition, compliance with environmental regulation might result in restrictions on some of our operations. If we do not comply with environmental regulation, regulatory agencies could seek to impose statutory, administrative and/or criminal liabilities on us, curtail our operations, or require significant expenditures on compliance, new equipment or technology, reporting obligations and research and development.
In addition to environmental regulations, we could also face civil liability in the event that private parties seek to impose liability on us for property damage, personal injury or other costs and losses. We cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against us and otherwise affect our operations and assets. If an action is filed against us or may otherwise affect our operations and assets, we could be required to make substantial expenditures to defend against or evidence our activities or to bring our Corporation, our operations and assets into compliance, which could have a material adverse effect on our business.
A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation, and mandatory GHG reporting requirements are in effect in both Canada and the US. Mandatory GHG emissions reductions requirements are expected to impose increased costs on our business, as is expected to be the case generally for thermal power producers in North America. We are subject to other air quality regulations, including mercury regulations. To the extent new or additional GHG, mercury or other air emission regulations may require us to incur costs that cannot be passed through to our customers under our PPA, the costs could be material and have a material adverse effect on our business. In terms of TransAlta's existing gas-fired facilities, we currently have change-in-law provisions allowing flow-through of carbon tax-related costs, and we expect that any new contracts will contain similar provisions.
Our surface mining operations are subject to laws and regulations establishing mining, environmental protection and reclamation standards for all aspects of surface mining. The estimated reclamation costs applicable to the Corporation's operations may be inaccurate and could require greater financial resources than currently anticipated. As a mine owner or operator, we must obtain permits from the applicable regulatory body providing for the authorization of certain mining operations that result in a disturbance of the surface. These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time. As a mine owner or operator, we may also be required to submit a bond or otherwise secure payment of certain long-term obligations including mine closure or reclamation costs. Surety bond costs have increased in recent years and the market terms of such bonds have generally become more unfavourable. In addition, the number of companies willing to issue surety bonds has decreased. We could be required to self-fund these obligations should we be unable to renew or secure the required surety bonds for our mining operations or if it becomes more economical to do so.
The laws and regulations in the various markets in which we operate are subject to change, which may materially adversely affect us.
Most of the markets in which we operate and intend to operate are subject to significant regulatory oversight and control. We are not able to predict whether there will be any further changes in the regulatory environment, including potential carbon and other environmental regulations, changes in market structure or market design, or changes in other laws and regulations. Existing market rules, regulations and reliability standards are often dynamic and may be
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revised or re-interpreted and new laws and regulations may be adopted or become applicable to us or our facilities, which could have a material adverse effect on us.
We manage these risks systematically through a regulatory and compliance program designed to reduce any potential negative impact on us. However, we cannot guarantee that we will be able to adapt our business in a timely manner in response to any changes in the regulatory regimes in which we operate, and such failure to adapt could have a material adverse effect on our business.
Regulatory authorities may also from time to time audit or investigate our activities in the markets in which we operate or pursue trading. Such audits or investigations may result in sanctions or penalties that may materially affect our future activities, reputation or financial status.
Our facilities are also subject to various licensing and permitting requirements in the jurisdictions in which we operate. Many of these licenses and permits need to be renewed from time to time. If we are unsuccessful in obtaining or renewing such licenses or permits, or the terms of such licenses or permits are changed in a manner that is adverse to our business, we could be materially adversely affected.
Any changes in the rules and regulations of provincial or state public utility commissions or other regulatory bodies in the other markets in which we compete, or may compete in the future, may materially adversely affect us.
We may be adversely affected if our supply of water is materially reduced.
Hydroelectric, natural gas and coal-fired facilities require continuous water flow for their operation. Shifts in weather or climate patterns, seasonable precipitation, the timing and rate of melting, run-off, and other factors beyond our control, may reduce the water flow to our facilities. Any material reduction in the water flow to our facilities would limit our ability to produce and market electricity from these facilities and could have a material adverse effect on us. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where we operate. Any such change in regulations could have a material adverse effect on us.
Variation in wind levels may negatively impact the amount of electricity generated at our wind facilities.
Given that wind is naturally variable, the level of electricity produced from our wind facilities is also variable. In addition, the strength and consistency of the wind resource at our wind facilities may vary from what we anticipate due to a number of factors, including the extent to which our site-specific historic wind data and wind forecasts accurately reflect actual long-term wind speeds, strength and consistency, the potential impact of climatic factors, the accuracy of our assumptions relating to, among other things, weather, icing, degradation, site access, wake and wind shear line losses and wind shear, and the potential impact of topographical variations.
A reduced amount of wind at the location of one or more of our wind facilities over an extended period may reduce the production from such facilities, as well as any environmental attributes that accrue to us related to that production and reduce our revenues and profitability.
Availability or disruption of fuel supply to our thermal plants could have an adverse impact on the operation of our facilities and our financial condition.
Our thermal facilities are reliant on having adequate natural gas and coal available to run the facilities reliably and at full capacity. As a result, we face the risk of not having adequate fuel supplies available due to insufficient natural gas transportation service, disruptions in fuel supplies due to weather, strikes, lock-outs, or breakdowns of equipment, or timing of receiving regulatory approvals. As well, the coal used to fuel the Centralia Thermal facility is sourced from the Powder River Basin in Montana and Wyoming through contracts to purchase and transport such coal to our Centralia Thermal facility. The loss of our suppliers or inability to receive coal at Centralia under our existing coal contracts at sufficient quantities, or at all, could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations. We could face the risk of adequate supply service due to our reliance on the Pioneer Pipeline as a significant provider of natural gas for our Sundance and Keephills units.
Our facilities rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets.
Our power generation facilities depend on electric transmission systems and related facilities owned and operated primarily by third parties to deliver the electricity that we generate to delivery points where ownership changes and we are paid. These grids operate with both regulatory and physical constraints that in certain circumstances may impede access to electricity markets. There may be instances in system emergencies in which our power generation facilities are
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physically disconnected from the power grid, or our production curtailed for periods of time. Most of our electricity sales contracts do not provide for payments to be made if electricity is not delivered.
Our power generation facilities may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which our power generation facilities are connected. Our power generation facilities in the future may not be able to secure access to this interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate PPAs or to construct new projects. In addition, we may not benefit from preferential arrangements in the future. Any such increased costs and delays could delay the commercial operation dates of any new projects and negatively impact our revenues and financial condition.
Cyberattacks may cause disruptions to our operations and could have a material adverse effect on our business.
We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. In today's continuously evolving cybersecurity threat landscape, any attacks or breaches of network or information systems may cause disruptions to our business operations or compromise proprietary, confidential or personal information of the Corporation, its customers, partners or others with whom the Corporation has dealings. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user-base (social engineering attacks), to using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems and antivirus software that exist on our network infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use or dissemination of proprietary, confidential or personal information and may cause disruptions to our operations.
We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our infrastructure, systems and data. Our cybersecurity program aligns with industry best practices to ensure that a holistic approach to security is maintained. We have implemented security controls to help secure our data and business operations including access control measures, intrusion detection and prevention systems, logging and monitoring of network activities, and implementing policies and procedures to ensure the secure operations of the business. We also purchase a cyber insurance policy and have established security awareness programs to help educate our users on cybersecurity risks and their responsibilities in helping protect the business.
While we have cyber insurance, as well as, systems, policies, procedures, practices, hardware, software applications, and data backups designed to prevent or limit the effect of security breaches of our network and infrastructure, there can be no assurance that these measures will be sufficient and that such security breaches will not occur or, if they do occur, that they will always be adequately addressed in a timely manner.
Our communications and monitoring technology and operating systems may experience interruptions or breaches in security which could subject us to increased operating costs and other liabilities.
We rely on technology, mainly on computer, telephone, satellite, cellular and related networks and infrastructure, to conduct our business and monitor the production of our generation facilities. These systems and infrastructure could be vulnerable to unforeseen problems including, but not limited to, cyberattacks, breaches, vandalism and theft. Our operations are dependent upon our ability to protect our information and operating technology against damage from fire, power loss, telecommunications failure or a similar catastrophic event. While we have dedicated resources for maintaining appropriate levels of cybersecurity and we use third-party technology to help protect us against security breaches and cyber incidents, our measures may not be effective and our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such security breaches and cyber incidents or other disruptions could jeopardize the security of information stored in and transmitted through our systems and network infrastructure, and could result in significant setbacks and potential liabilities, and deter future customers. Additionally, we must be able to protect our generation facility infrastructure against physical damage and service disruption from any of a variety of causes.
Any damage or failure that causes an interruption in operations could have an adverse effect on our customers. While we have systems, policies, hardware, practices and procedures designed to prevent or limit the effect of failure or interruptions of our generation facilities and infrastructure, there can be no assurance that these measures will be sufficient and that any such failures or interruptions will not occur or, if they do occur, that they will be adequately addressed in a timely manner.
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We operate in a highly competitive environment and may not be able to compete successfully.
We operate in a number of Canadian provinces, as well as in the United States and Australia. These areas of operation are affected by competition ranging from large utilities to small independent power producers, as well as private equity, international conglomerates, traditional energy companies and technology firms. In addition, potential customers may look to deploy their own capital to self-supply their own electricity needs. Some competitors have significantly greater financial and other resources than we do. Such competition could have a material adverse effect on our business. Emerging technology affecting the demand, generation, distribution or storage of electricity may also significantly impact our business and ability to compete.
Changes in the price of electricity and availability of fuel supplies required to generate electricity may materially adversely affect our business.
A significant portion of our revenues are tied, either directly or indirectly, to the market price for electricity in the markets in which we operate. Market electricity prices are impacted by a number of factors, including the strength of the economy, the available transmission capacity, the price of fuel that is used to generate electricity (and, accordingly, certain of the factors that affect the price of fuel described below); the management of generation and the amount of excess generating capacity relative to load in a particular market, the cost of controlling emissions of pollution, including potentially the cost of carbon, the structure of the particular market, increased adoption of energy-efficiency and conservation initiatives, and weather conditions that impact electrical load. As a result, we cannot accurately predict future electricity prices and electricity price volatility could have a material adverse effect on us.
We buy natural gas and a portion of our coal to supply the fuel needed to generate electricity. We could be materially adversely affected if the cost of fuel that we must buy to generate electricity increases to a greater degree than the price that we can obtain for the electricity that we sell. Several factors affect the price of fuel, many of which are beyond our control, including:
▪prevailing market prices for fuel;
▪global demand for energy products;
▪the cost of carbon and other environmental concerns;
▪weather-related disruptions affecting the ability to deliver fuels or near term demand for fuels;
▪increases in the supply of energy products in the wholesale power markets;
▪the extent of fuel transportation capacity or cost of fuel transportation service into our markets; and
▪the cost of mining or extraction that, in turn, depends on various factors such as labour market pressures, equipment replacement costs and permitting.
Changes in any of these factors may increase our cost of producing power or decrease the amount of revenue received from the sale of power, which could have a material adverse effect on us.
Changes in general economic and market conditions may have a material adverse effect on us.
Adverse changes in general economic and market conditions and, more specifically, in the markets in which we operate, could negatively impact demand for electricity, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of plant, property and equipment, results of financing efforts, or credit risk and counterparty risk, which could cause us to suffer a material adverse effect.
We may be unsuccessful in legal actions.
We are occasionally named as a defendant in claims and legal actions and as a party in commercial disputes that are resolved by arbitration or other legal proceedings. We may also bring legal actions against third parties as part of a commercial dispute through an arbitration or other legal proceeding. There can be no assurance that we will be successful in any such claim or defense or that any claim or legal action that is decided adverse to us will not materially and adversely affect us. See "Legal Proceedings and Regulatory Actions."
Risks relating to TransAlta's development and growth projects and acquisitions may materially and adversely affect us.
Development and growth projects and acquisitions that we undertake may be subject to execution and capital cost risks, including, but not limited to, risks relating to regulatory approvals, third-party opposition, cost escalations, construction delays, shortages of raw materials or skilled labour and capital constraints. The occurrences of these risks could have a material and adverse impact on us, our financial condition, results of operations and cash flows.
Expansion of our business through development projects and acquisitions may place increased demands on our management, operating systems, internal controls and financial and physical resources. In addition, the process of integrating acquired businesses or development projects may involve unforeseen difficulties. Failure to successfully
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manage or integrate any acquired businesses or development projects could have a material adverse impact on us, our financial condition, results of operations and cash flows. Further, we cannot make assurances that we will be successful in integrating any acquisition or that the commercial opportunities or operational synergies of any acquisition will be realized as expected.
We may pursue acquisitions in new markets that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to us currently, which may adversely affect our ability to receive revenues or enforce our rights in connection with any such foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may acquire, thus limiting our ability to control the operation of such projects. Any existing or new operations may also be subject to significant political, economic and financial risks, which vary by country, and may include: (a) changes in government policies or personnel; (b) changes in general economic conditions; (c) restrictions on currency transfer or convertibility; (d) changes in labour relations; (e) political instability and civil unrest; (f) regulatory or other changes in the local electricity market; and (g) breach or repudiation of important contractual undertakings by governmental entities and expropriation and confiscation of assets and facilities for less than fair market value.
With respect to acquisitions, we cannot make assurances that we will identify suitable transactions or that we will have access to sufficient resources, through our credit facilities, the capital markets or otherwise, to pursue and complete any identified acquisition opportunities on a timely basis and at a reasonable cost. Any acquisition that we propose or complete would be subject to normal commercial risks that the transaction may not be completed on the terms negotiated, on time, or at all. An unavoidable level of risk remains regarding potential undisclosed or unknown liabilities relating to any acquisition. The existence of such undisclosed liabilities may have a material adverse impact on our business, financial condition, results of operations and cash flows.
We may have difficulty raising needed capital in the future, which could significantly harm
our business.
To the extent that our sources of cash and cash flow from operations are insufficient to fund our activities, we may need to raise additional funds. Additional financing may not be available when needed, and if such financing is available, it may not be available on terms that are favourable to our business.
Recovery of the capital investment in power projects generally occurs over a long period of time. As a result, we must obtain funds from equity or debt financings, including tax equity transactions, or from government grants, to help finance the acquisition of projects and to help pay the general and administrative costs of operating our business. Our ability to arrange financing, either at the corporate level or at the subsidiary level (including non-recourse project debt), and the costs of such capital are dependent on numerous factors, including: (a) general economic and capital market conditions; (b) credit availability from banks and other financial institutions; (c) investor confidence and the markets in which we conduct operations; (d) our financial performance and/or the expected financial performance of certain assets; (e) our level of indebtedness and compliance with covenants in our debt agreements; and (f) our cash flow.
An increase in interest rates or a reduction in the availability of project debt financing could reduce the number of projects that we are able to finance. If we are unable to raise additional funds when needed, we could be required to delay acquisition and construction of growth projects (including the conversion to gas), reduce the scope of projects, abandon or sell some or all of our projects or generation facilities, or default on our contractual commitments in the future, any of which could adversely affect our business, financial condition and results of operations.
TransAlta Corporation's debt securities will be structurally subordinated to any debt of our subsidiaries that are currently outstanding or may be incurred in the future.
We operate our business through, and a majority of our assets are held by, our subsidiaries, including partnerships. Our results of operations and ability to service indebtedness are dependent upon the results of operations of our subsidiaries, including TransAlta Renewables, and the payment of funds by these subsidiaries to TransAlta in the form of loans, dividends or otherwise. Our subsidiaries may be restricted in their ability to pay amounts due, or make any funds available for payment of, debt securities issued by TransAlta, whether by dividends, interests, loans, advances or other payments. In addition, the payment of dividends and the making of loans, advances and other payments to us by our subsidiaries may be subject to statutory or contractual restrictions.
In the event of the liquidation of any subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees,before being used to pay TransAlta's indebtedness, including any debt securities issued by TransAlta. Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior for such subsidiary to any debt securities issued by TransAlta.
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Our subsidiaries have financed some investments using non-recourse project financing. Each non-recourse project loan is structured to be repaid out of cash flow provided by the investment. In the event of a default under a financing agreement that is not cured, the lenders would generally have rights to the related assets. In the event of foreclosure after a default, our subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate. Although a default under a project loan will not cause a default with respect to any debt securities issued by TransAlta, it may materially affect our ability to service our outstanding indebtedness.
A downgrade of our credit ratings could materially and adversely affect us.
Rating agencies regularly evaluate us, basing their ratings of our long-term and short-term debt, along with our issuer rating on a number of factors. There can be no assurance that one or more of our credit ratings and the corresponding outlook will not be changed. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions with us. A credit rating downgrade could potentially impair our ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit our access to private and public credit markets and increase the costs of borrowing under our existing credit facilities. For further information on posting collateral, please see Note 16(F) of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Changes in opinions of our Corporation from external parties may have a material adverse effect on us.
Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, financiers and other entities. Our reputation is one of our most valued assets. The potential for harming our reputation exists in every business decision and all risks can have an impact on reputation, which in turn can negatively impact our business and securities. Reputational risk cannot be managed in isolation from other forms of risk. Negative impacts from a compromised reputation could include revenue loss, reduction in customer base, and decreased value of our securities.
We may fail to meet financial expectations.
Our quarterly revenue, earnings, cash flows and results of operations are difficult to predict and fluctuate from quarter to quarter. Our quarterly results of operations are influenced by a number of factors, including the risks described in this AIF, many of which are outside of our control, which may cause such results to fall below market expectations. Although we base our planned operating expenses in part on our expectations of future revenue, a significant portion of our expenses are relatively fixed in the short-term. If revenue for a particular quarter is lower than expected, we likely will be unable to proportionately reduce our operating expenses for that quarter, which will adversely affect our results of operations for that quarter.
Our cash dividend payments are not guaranteed.
The payment of dividends is not guaranteed and could fluctuate. The Board has the discretion to determine the amount and timing of any dividends to be declared and paid to our shareholders. In addition, the payment of dividends on common shares is, in all cases, subject to prior satisfaction of preferential dividends applicable to each series of our first preferred shares. We may alter our dividend policy at any time.The Board's determination to declare dividends will depend on, among other things, results of operations; financial condition; current and expected future levels of earnings; operating cash flow; liquidity requirements; market opportunities; income taxes; maintenance and growth capital expenditures; debt repayments; legal, regulatory and contractual constraints; working capital requirements; tax laws and other relevant factors. Our short- and long-term borrowings may prohibit us from paying dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying the dividend.
Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future. If we continue to pay dividends at the current level, we may not retain a sufficient amount of cash to finance growth opportunities, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn. The Board, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time. A decline in the market price or liquidity, or both, of our common shares could result if the Board establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends.
We are dependent on the operations of our facilities for our cash availability. The actual amount of cash available for dividends to holders of our common shares will depend upon numerous factors relating to each of our generation facilities including: operating performance of our generation facilities, profitability, changes in gross margin, fluctuations
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in working capital, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictions contained in the instruments governing any indebtedness. Any reduction in the amount of cash available for distribution from our generation facilities will reduce the amount of cash available to pay dividends to holders of our common shares.
The market price for our common shares may be volatile.
The market price for our common shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond our control, including: (a) actual or anticipated fluctuations in our results of operations; (b) recommendations by securities research analysts; (c) changes in the economic performance or market valuations of other companies that investors deem comparable; (d) the loss or resignation of executive officers and other key personnel; (e) sales or perceived sales of additional common shares; (f) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving us or our competitors; and (g) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the power generation industry or our target markets.
Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and such fluctuations have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values that may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions' respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in our common shares by those institutions, which could adversely affect the trading price of our common shares.
Our revenues may be reduced upon expiration or termination of PPAs.
We sell power under PPAs that expire at various times. In addition, these PPAs may be subject to termination in certain circumstances, including default by the facility or plant owner or operator. When a PPA expires or is terminated, it could result in us having less stable cash flows and it is possible that the price received by the relevant facility or plant for power under subsequent selling arrangements may be reduced significantly. It is also possible that to the extent a PPA is negotiated after the initial PPAs have run their course, the new contract may not be available at prices that permit the continued operation of the affected facility or plant on a profitable basis. If this occurs, the affected facility or plant may be forced to permanently cease operations.
If Mangrove is successful in its claim to set aside the Brookfield Investment, it could have a material adverse effect on our business.
If Mangrove is successful in its claim against the Corporation to have the Brookfield transaction set aside, this could have a material adverse effect on the Corporation, including its ability to continue to return capital through share buybacks, meet certain financial obligations, continue to advance its conversion to gas strategy and execute on other growth opportunities and strategic plans. The Corporation would likely need to raise additional cash or working capital through the public or private sale of debt or equity securities, sale of assets, funding from joint-venture or strategic partners, debt financing or short-term loans, and the terms of such transactions may be unduly expensive or burdensome to the Corporation relative to the terms of the Brookfield Investment and disadvantageous to our existing shareholders. There can be no assurance that the Corporation would be successful in securing alternative sources of capital.
Trading risks may have a material adverse effect on our business.
Our trading and marketing business frequently involves establishing trading positions in the wholesale energy markets on both a medium-term and short-term basis and on both an asset and proprietary basis. To the extent that we have long positions in the energy markets, a downturn in market prices will result in losses from a decline in the value of such long positions. Conversely, to the extent that we enter into forward sales contracts to deliver energy that we do not own, or take short positions in the energy markets, an upturn in market prices will expose us to losses as we attempt to cover any short positions by acquiring energy in a rising market.
In addition, from time to time, we may have a trading strategy consisting of simultaneously holding a long position and a short position, from which we expect to earn a profit based on changes in the relative value of the two positions. If, however, the relative value of the two positions changes in a direction or manner that we did not anticipate, we would realize losses from such a paired position.
If the strategy that we use to hedge our exposures to these various risks is not effective, we could incur significant losses. Our trading positions can be impacted by volatility in the energy markets that, in turn, depend on various factors,
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including weather in various geographical areas and short-term supply and demand imbalances, which cannot be predicted with any certainty. A shift in the energy markets could adversely affect our positions, which could also have a material adverse effect on our business.
We use a number of risk management controls conducted by our independent Risk Management group in order to limit our exposure to risks arising from our trading activities. These controls include risk capital limits, Value at Risk, Gross Margin at Risk, tail risk scenarios, position limits, concentration limits, credit limits, and approved product controls. We cannot guarantee that losses will not occur and such losses may be outside the parameters of our risk controls.
Certain of the contracts to which we are a party require that we provide collateral against our obligations.
We are exposed to risk under certain financial derivative contracts and electricity and natural gas purchase and sale contracts entered into for the purposes of hedging and proprietary trading. The terms and conditions of these contracts require us to provide collateral when the fair value of these contracts is in excess of any credit limits granted by our counterparties and the contract obliges that we provide the collateral. The change in fair value of these contracts occurs due to changes in commodity prices. These contracts include: (a) financial derivative contracts when forward commodity prices are more or less than contracted prices, depending on the transactions; (b) purchase agreements, when forward commodity prices are less than contracted prices; and (c) sales agreements, when forward commodity prices exceed contracted prices. Downgrades in our creditworthiness by certain credit rating agencies may decrease the credit limits granted by our counterparties and, accordingly, increase the amount of collateral that we may have to provide, which could materially adversely affect us.
If counterparties to our contracts are unable to meet their obligations, we may be materially and adversely affected.
If purchasers of our electricity and steam or other contractual counterparties default on their obligations, we may be materially and adversely affected. While we have procedures and controls in place to manage our counterparty credit risk before entering into contracts, all contracts inherently contain default risk. Moreover, while we seek to monitor trading activities to ensure that the credit limits for counterparties are not exceeded, we cannot guarantee that a party will not default. If counterparties to our contracts are unable to meet their obligations, we could suffer a reduction in revenue that could have a material adverse effect on our business.
Because of our multinational operations, we are subject to currency rate risk and regulatory and political risk.
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the cash flows from those operations, the acquisition of equipment and services from foreign suppliers, and our US-dollar denominated debt. Our exposures are primarily to the US and Australian currencies, and changes in the values of these currencies relative to the Canadian dollar could negatively impact our operating cash flows or the value of our foreign investments. While we attempt to manage this risk by using hedging instruments, including cross-currency interest rate swaps, forward exchange contracts and matching revenues and expenses by currency at the Corporate level, there can be no assurance that these risk management efforts will be effective, and fluctuations in these exchange rates may have a material adverse effect on our business.
In addition to currency rate risk, our foreign operations may be subject to regulatory and political risk. Any change to the regulations governing power generation or the political climate in the countries where we have operations could impose additional costs and have a material adverse effect on us.
We are not able to insure against all potential risks and may become subject to higher insurance premiums.
Our business is exposed to the risks inherent in the construction and operation of electricity generation facilities, such as breakdowns, manufacturing defects, natural disasters, injury, damage to third parties, theft, terrorist attacks and sabotage. We are also exposed to environmental risks. We maintain insurance policies, covering usual and customary risks associated with our business, with creditworthy insurance carriers. Our insurance policies, however, may not cover losses, or may be subject to limitations in coverage as a result of force majeure, natural disasters, terrorist or cyberattacks or sabotage, among other perils. In addition, we generally do not maintain insurance for certain environmental risks, such as environmental contamination. Our insurance policies are subject to annual review by the respective insurers and may not be renewed at all or on similar or favourable terms. A significant uninsured loss or a loss significantly exceeding the limits of our insurance policies or the failure to renew such insurance policies on similar or favourable terms could have a material adverse effect on our business, financial condition and results of operations.
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Our insurance coverage may not be available in the future on commercially reasonable terms or adequate insurance limits may not be available in the market. In addition, the insurance proceeds received for any loss or damage to any of our generation facilities may not be sufficient to permit us to continue to make payments on our debt.
Provision for income taxes may not be sufficient.
Our operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing. In addition, our tax filings are subject to audit by taxation authorities. While we believe that our tax filings have been made in material compliance with all applicable tax interpretations, regulations, and legislation, we cannot guarantee that we will not have disagreements with taxation authorities with respect to our tax filings that could have a material adverse effect on our business.
The Corporation and its subsidiaries are subject to changing tax laws, treaties and regulations in and between countries. Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense that could have a material adverse impact on us.
We are subject to uncertainties regarding when we will become cash taxable.
Our anticipated cash tax horizon is subject to risks, uncertainties and other factors that could cause the cash tax horizon to occur sooner than currently projected. In particular, our anticipated cash tax horizon is subject to risks pertaining to changes in our operations, asset base, corporate structure or changes to tax legislation, regulations or interpretations. In the event we become cash taxable sooner than projected, our cash available for distribution and our dividend could decrease, which could in turn have a material adverse impact on the value of our shares.
If we fail to attract and retain key personnel, we could be materially adversely affected.
The loss of any of our key personnel or our inability to attract, train, retain and motivate additional qualified management and other personnel could have a material adverse effect on our business. Competition for these personnel is intense and there can be no assurance that we will be successful in this regard.
If we are unable to successfully negotiate new collective bargaining agreements with our unionized workforce, as required from time to time, we will be adversely affected.
While we believe we have a satisfactory relationship with our unionized employees, we cannot guarantee that we will be able to successfully negotiate or renegotiate our collective bargaining agreements on terms agreeable to TransAlta. In 2020, we successfully renegotiated two collective bargaining agreements. We expect to renegotiate three collective bargaining agreements in 2021 and expect to renegotiate four collective bargaining agreements in 2022. Any problems in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on us.
Employees
The Corporation is required to develop and retain a skilled workforce for its operations. Many of the employees of the Corporation possess specialized skills and training and the Corporation must compete in the marketplace for these workers. As at Dec. 31, 2020, we had 1,476 active employees, which includes full-time, part-time and temporary employees, of which 486 were employed in our Alberta Thermal segment (including our SunHills Mining operation), 187 were employed in our Centralia segment, 197 were employed in our North American Gas segment, 83 were employed in our Wind and Solar business, 83 were employed in our Hydro business, 76 were employed in our Energy Marketing business and the remaining 364 employees were employed in our Corporate segment. Approximately 46 per cent of our employees are represented by labour unions. We are currently a party to 12 different collective bargaining agreements. We expect to renegotiate three collective bargaining agreements in 2021 and expect to renegotiate four collective bargaining agreements in 2022.
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Capital and Loan Structure
Our authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. As at March 2, 2021, there were 269,883,087 common shares outstanding and 10,175,380 Series A Shares, 1,824,620 Series B Shares, 11,000,000 Series C Shares, 9,000,000 Series E Shares, 6,600,000 Series G Shares and 400,000 Series I Shares outstanding (as defined below). The Corporation does not have any escrowed securities.
Common Shares
Each common share of TransAlta Corporation entitles the holder thereof to one vote for each common share held at all meetings of shareholders of the Corporation, except meetings at which only holders of another specified class or series of shares are entitled to vote, to receive dividends if, as and when declared by the Board, subject to prior satisfaction of preferential dividends applicable to any first preferred shares, and to participate rateably in any distribution of our assets upon a liquidation, dissolution or winding up and subject to prior rights and privileges attaching to first preferred shares. The common shares are not convertible and are not entitled to any preemptive rights. The common shares are not entitled to cumulative voting.
Normal Course Issuer Bid
On May 26, 2020, the TSX accepted our notice filed to implement an NCIB for a portion of its common shares. The Board has authorized repurchases of up to a maximum of 14,000,000 common shares, representing approximately seven per cent of TransAlta's public float. Purchases under the NCIB are expected to be made through open market transactions on the TSX and any alternative Canadian trading platforms, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.
The period during which TransAlta is authorized to make purchases under the NCIB began on May 29, 2020, and ends on May 28, 2021, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation’s election.
Under TSX rules, not more than 228,157 common shares (being 25 per cent of the average daily trading volume on the TSX of 912,630 common shares for the six months ended April 30, 2020) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.
In connection with the investment by Brookfield, the Corporation has indicated that it intends to return up to $250 million of capital to shareholders through share repurchases within three years of receiving the first tranche of the investment (which occurred on May 1, 2019).
During the year ended Dec. 31, 2020, the Corporation purchased and cancelled 7,352,600 common shares at an average price of $8.33 per common share, for a total cost of $61 million. For further information please see Note 27 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
First Preferred Shares
We are authorized to issue an unlimited number of first preferred shares, issuable in series and, with respect to each series, the Board is authorized to fix the number of shares comprising the series and determine the designation, rights, privileges, restrictions and conditions attaching to such shares, subject to certain limitations.
The first preferred shares of all series rank senior to all other shares of TransAlta Corporation with respect to priority in payment of dividends and with respect to distribution of assets in the event of liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital. Holders of first preferred shares are entitled to receive cumulative quarterly dividends on the subscription price thereof as and when declared by the Board at the rate established by the Board at the time of issue of shares of a series. No dividends may be declared or paid on any other shares of TransAlta Corporation unless all cumulative dividends accrued upon all outstanding first preferred shares have been paid or declared and set apart. In the event of the liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of TransAlta Corporation until the holders of first preferred shares shall have been paid the subscription price of the shares, plus a sum equal to the premium payable on a redemption, plus a sum equal to the arrears of dividends accumulated on the first preferred shares to the date of such liquidation, dissolution, winding up or reduction of stated capital, as applicable. After payment of such amount, the holders of first preferred shares shall not be entitled to share further in the distribution of our assets.
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The Board may include, in the share conditions attaching to a particular series of first preferred shares, certain voting rights effective upon our failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25.00 of subscription price on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of TransAlta if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Subject to the share conditions attaching to any particular series providing to the contrary, we may redeem the first preferred shares of a series, in whole or from time to time in part, at the redemption price applicable to each series and we have the right to acquire any of the first preferred shares of one or more series by purchase for cancellation in the open market or by invitation for tenders at a price not to exceed the redemption price applicable to the series.
Series A Shares
Twelve million Series A Shares were issued on Dec. 10, 2010, with a coupon of 4.60 per cent, for gross proceeds of $300 million. On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares. Certain provisions of the Series A Shares are discussed below.
Dividends on Series A Shares
The holders of Series A Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series A Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares and the Series B Shares described below, and will remain unchanged over the life of the Series A Shares.
Redemption of Series A Shares
The Series A Shares were redeemable by TransAlta, at its option, in whole or in part, on March 31, 2016, and will be redeemable on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series A Shares of the redemption of all of the Series A Shares, the right of a holder of Series A Shares to convert such Series A Shares shall terminate and we shall not be required to give notice to the registered holders of the Series A Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series A Shares.
Conversion of Series A Shares into Series B Shares
The holders of the Series A Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series B of TransAlta (the "Series B Shares"), subject to certain conditions, on March 31, 2016, and will again have the right to convert on March 31 in every fifth year thereafter. The holders of the Series B Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means, the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the
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dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent.
The Series A Shares and Series B Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series A Shares and Series B Shares are identical in all material respects.
On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis.
Voting Rights
The holders of the Series A Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series A Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series A Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series A Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation
Modification
The provisions attaching to the Series A Shares as a class may be amended with the written approval of all the holders of Series A Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
Series B Shares
1,824,620 Series B Shares were issued on March 31, 2016. Certain provisions of the Series B Shares are discussed below.
Dividends on Series B Shares
The holders of Series B Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, floating rate cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after conversion, the holders of Series B Shares shall be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means, the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares described above and the Series B Shares and will remain unchanged over the life of the Series B Shares.
Redemption of Series B Shares
The Series B Shares are redeemable by TransAlta, at its option, in whole or in part, on March 31, 2021, and on March 31 in every fifth year thereafter by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series B Shares of the redemption of all of the Series B Shares, the right of a holder of Series B Shares to convert such Series B Shares shall terminate and we shall not be required to give notice to the
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registered holders of the Series B Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series B Shares.
Conversion of Series B Shares into Series A Shares
The holders of the Series B Shares have the right to convert all or any of their shares into cumulative redeemable fixed rate first preferred shares, Series A Shares, subject to certain conditions, on March 31, 2021, and on March 31 in every fifth year thereafter. The holders of the Series A Shares will be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends payable on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent.
The Series A Shares and Series B Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series A Shares and Series B Shares are identical in all material respects.
Voting Rights
The holders of the Series B Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series B Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series B Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series B Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series B Shares as a class may be amended with the written approval of all the holders of Series B Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
Series C Shares
Eleven million cumulative redeemable rate reset first preferred shares, Series C (the "Series C Shares") were issued on Nov. 30, 2011, with a coupon of 4.60 per cent, for gross proceeds of $275 million. Certain provisions of the Series C Shares are discussed below.
Dividends on Series C Shares
The holders of Series C Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series C Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.10 per cent. This spread will apply to both the Series C Shares and the Series D Shares described below, and will remain unchanged over the life of the Series C Shares.
Redemption of Series C Shares
The Series C Shares were redeemable by TransAlta, at its option, in whole or in part, on June 30, 2017, and will be redeemable on June 30 in every fifth year thereafter by the payment of an amount in cash for each share to be
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redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold). On June 30, 2017, none of the Series C Shares were redeemed.
If we give notice to the holders of the Series C Shares of the redemption of all of the Series C Shares, the right of a holder of Series C Shares to convert such Series C Shares shall terminate and we shall not be required to give notice to the registered holders of the Series C Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series C Shares.
Conversion of Series C Shares into Series D Shares
The holders of the Series C Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series D Shares, subject to certain conditions, on June 30, 2017, and will again have the right to convert on June 30 in every fifth year thereafter. The holders of the Series D Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.10 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.10 per cent.
The Series C Shares and Series D Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series C Shares and Series D Shares are identical in all material respects.
On June 15, 2017, 827,628 Series C Shares were tendered for conversion into Series D Shares which is less than the one million shares required to give effect to conversions into Series D Shares. As a result, none of the Series C Shares were converted into Series D Shares on June 30, 2017.
Voting Rights
The holders of the Series C Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series C Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series C Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series C Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series C Shares as a class may be amended with the written approval of all the holders of Series C Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
Series E Shares
Nine million cumulative redeemable rate reset first preferred shares, Series E Shares were issued on Aug. 10, 2012, for gross proceeds of $225 million. Certain provisions of the Series E Shares are discussed below.
Dividends on Series E Shares
The holders of Series E Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September, and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series E Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash
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dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta Corporation on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.65 per cent. This spread will apply to both the Series E Shares and the Series F Shares described below, and will remain unchanged over the life of the Series E Shares.
Redemption of Series E Shares
The Series E Shares were redeemable by TransAlta Corporation, at its option, in whole or in part, on Sep. 30, 2017, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold). On Sep. 30, 2017, none of the Class E Shares were redeemed.
If we give notice to the holders of the Series E Shares of the redemption of all of the Series E Shares, the right of a holder of Series E Shares to convert such Series E Shares shall terminate and we shall not be required to give notice to the registered holders of the Series E Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series E Shares.
Conversion of Series E Shares into Series F Shares
The holders of the Series E Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series F Shares"), subject to certain conditions, on Sep. 30, 2017, and will again have the right to convert on September 30 in every fifth year thereafter. The holders of the Series F Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.65 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.65 per cent.
The Series E Shares and Series F Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series E Shares and Series F Shares are identical in all material respects.
On Sep. 15, 2017, 133,969 Series E Shares were tendered for conversion into Series F Shares which is less than the one million shares required to give effect to conversions into Series F Shares. As a result, none of the Series E Shares were converted into Series F Shares on Sep. 30, 2017.
Voting Rights
The holders of the Series E Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series E Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series E Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series E Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series E Shares as a class may be amended with the written approval of all the holders of Series E Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
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Series G Shares
6.6 million cumulative redeemable rate reset first preferred shares, Series G Shares, were issued on Aug. 15, 2014, for gross proceeds of $165 million. Certain provisions of the Series G Shares are discussed below.
Dividends on Series G Shares
The holders of Series G Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series G Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta Corporation on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.80 per cent. This spread will apply to both the Series G Shares and the Series H Shares described below, and will remain unchanged over the life of the Series G Shares.
Redemption of Series G Shares
The Series G Shares were redeemable by TransAlta Corporation, at its option, in whole or in part, on Sep. 30, 2019, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series G Shares of the redemption of all of the Series G Shares, the right of a holder of Series G Shares to convert such Series G Shares shall terminate and we shall not be required to give notice to the registered holders of the Series G Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series G Shares.
Conversion of Series G Shares into Series H Shares
The holders of the Series G Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series H Shares, subject to certain conditions, on Sep. 30, 2019, and will again have the right to convert on September 30 in every fifth year thereafter. The holders of the Series H Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.80 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.80 per cent.
The Series G Shares and Series H Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series G Shares and Series H Shares are identical in all material respects.
On Sep. 17, 2019, 140,730 Series G Shares were tendered for conversion into Series H Shares which is less than the one million shares required to give effect to conversions into Series H Shares. As a result, none of the Series G Shares were converted into Series H Shares on Sep. 30, 2019.
Voting Rights
The holders of Series G Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series G Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series G Shares will be entitled to receive notice of
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and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series G Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series G Shares as a class may be amended with the written approval of all the holders of Series G Shares outstanding or by at least two-thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
Series I Shares
The Series I Shares have a perpetual term and will rank pari passu to all existing series of first preferred shares of the Company with respect to dividends and liquidation preferences. The Series I Shares are entitled to a 7% cumulative dividend payable quarterly in cash.
Under the Investment Agreement with Brookfield, redemption of the Series I Shares will be satisfied through the Hydro Equity Interest (as defined below), or in some cases cash, based on their redemption price. The redemption price payable is equal to the subscription price paid by Brookfield together with all accrued but unpaid dividends thereon (the “Redemption Price”). Upon the occurrence of an Optional Redemption, as defined and described below, or a Cash Acceleration Event, as defined and described below, the Corporation will pay the Redemption Price in cash (the “Cash Redemption Amount”).
Except in the case of an Optional Redemption by the Corporation or a Cash Acceleration Event, as described below, the Series I Shares will be exchangeable into interests (the “Hydro Equity Interest”) in the equity (the “Hydro Equity”) of TA Alberta Hydro LP (the “Hydro Assets Owner”), a special purpose vehicle formed by the Corporation . At any time after Dec. 31, 2024, Brookfield will be entitled to exchange all, but not less than all, of the Series I Shares requiring the Corporation to redeem or exchange all of the Series I Shares held by Brookfield (minus the number of Series I Shares that have been redeemed pursuant to an Optional Redemption) (the “Exchange Right”).
Prior to any Optional Redemption by the Corporation, the exercise of the Exchange Right or the occurrence of an Equity Acceleration Event, as defined and described below, will entitle Brookfield to receive that percentage of a Hydro Equity Interest that is equal to the aggregate Redemption Price for all Series I Shares issued to Brookfield divided by the tax affected equity value of the Hydro Assets Owner, as further described in the Investment Agreement (the “Equity Redemption Amount”). The maximum Hydro Equity Interest issuable to Brookfield upon the exercise of the Exchange Right is 49% of the total Hydro Equity. The balance of the Redemption Price will be paid by the Corporation in cash.
If, at the time the Exchange Right is exercised, the Equity Redemption Amount is insufficient to permit Brookfield to acquire 49% of the Hydro Equity, Brookfield has a one-time top-up option, exercisable until Dec. 31, 2028, to acquire an additional amount of Hydro Equity. As long as Brookfield holds at least 8.5% of the issued and outstanding common shares, Brookfield may purchase: (a) if the 20- day volume weighted average price (“VWAP”) of the Common Shares is not less than $14, up to an additional 10% of Hydro Equity, to a maximum interest of 49% of the Hydro Equity; or (b) if the 20-day VWAP of the common shares is not less than $17, the additional percentage required that would bring Brookfield’s ownership level up to but not exceeding 49% of the Hydro Equity. If the Exchange Right is exercised and the Equity Redemption Amount is insufficient to permit Brookfield to acquire at least 25% of the Hydro Equity, Brookfield will have an option to acquire that additional percentage of Hydro Equity that would result in Brookfield having 25% of the Hydro Equity upon payment in cash. If Brookfield exercises its top-up option, the cash amount payable by Brookfield is calculated as the same price as in the case of an exchange for the Hydro Equity Interest, however, in such a case, the price is based on the equity value of the Hydro Assets Owner without any reduction for the tax deficiency value associated with certain tax pools. Exercise of this top-up option triggers a lock-up obligation of Brookfield for a further period of 18 months following its exercise.
At any time after Dec. 31, 2028, the Corporation may redeem the Series I Shares and the related debentures, in whole or in part, at the Redemption Price (the “Optional Redemption”) provided that the minimum proceeds to Brookfield for each such redemption (other than the final redemption) may not be less than $100,000,000 and further provided that all Series I Shares and related debentures must be redeemed by the Company within 36 months of the date of the first Optional Redemption.
The Investment Agreement also provides for certain acceleration events (the “Acceleration Events”). In the event of bankruptcy or a breach of a certain material covenants by the Corporation (each, an “Equity Acceleration Event”), Brookfield will be entitled to give notice and will be entitled to the Equity Redemption Amount. If an Equity Acceleration Event occurs before Dec. 31, 2024, a true-up payment will be made by Brookfield to the Corporation or by the
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Corporation to Brookfield to account for the difference between $1.95 billion and the tax-effected value of the Hydro Equity Interest calculated as of a date (to be determined by Brookfield) within the period commencing Jan. 1, 2025 and ending Dec. 31, 2027. Any difference in favour of Brookfield between the true-up value and the value of the Hydro Equity Interest issued to Brookfield is to be satisfied by delivery of additional Hydro Equity. If the Company does not obtain the requisite regulatory approvals for the exchange for Hydro Equity contemplated by the Exchange Right or the Equity Redemption Amount or a final order is made which enjoins the completion of the Exchange Right (the “Cash Acceleration Event”), then Brookfield will be entitled to the Cash Redemption Amount.
Related-Party Articles Provisions
The articles of the Corporation contain provisions restricting the ability of the Corporation to enter into a "Specified Transaction" with a "Major Shareholder." A Specified Transaction requires the approval of a majority of the votes cast by holders of voting shares of the Corporation, as well as the approval of a majority of the votes cast by holders of such voting shares, excluding any Major Shareholder. A Major Shareholder generally means the beneficial owner of more than 20 per cent of the outstanding voting shares of the Corporation. The articles contain a broad definition of beneficial ownership, and in particular, a person is considered to beneficially own shares owned by its associates and affiliates, as those terms are defined in the articles. Transactions that are considered to be Specified Transactions include the following: a merger or amalgamation of the Corporation with a Major Shareholder; the furnishing of financial assistance by the Corporation to a Major Shareholder; certain sales of assets or provision of services by the Corporation to a Major Shareholder or vice versa; certain issuances of securities by the Corporation that increase the proportionate voting interest of a Major Shareholder; a reorganization or recapitalization of the Corporation that increases the proportionate voting interest of a Major Shareholder; and the creation of a class or series of non-voting shares of the Corporation that has a residual right to participate in earnings of the Corporation and assets of the Corporation upon dissolution or winding up.
Shareholder Rights Plan
The Corporation implemented a shareholder rights plan (the "Rights Plan") pursuant to a Shareholder Rights Plan Agreement (the "Rights Plan Agreement") dated as of Oct. 13, 1992, as amended and restated as of April 26, 2019, between the Corporation and AST Trust Company (Canada) (the successor to CST Trust Company). The Shareholder Rights Plan was last confirmed at our annual and special meeting of shareholders on April 26, 2019, and will expire at the close of business on the date of our 2022 Annual Meeting of Shareholders, unless ratified and extended by a further vote of the shareholders. The Rights Plan Agreement was assigned by AST Trust Company (Canada) to Computershare Trust Company of Canada effective Nov. 22, 2019. For further particulars, reference should be made to the Rights Plan Agreement, as amended and restated. A copy of the Rights Plan Agreement may be obtained by contacting the Corporate Secretary, TransAlta Corporation, 110 - 12th Avenue S.W., Calgary, Alberta T2R 0G7; telephone: (403) 267-7110; or by email: corporate_secretary@transalta.com. A copy of the Rights Plan Agreement is also available electronically on SEDAR under our profile, which can be accessed at www.sedar.com, and on the SEC's EDGAR system at www.sec.gov.
Credit Facilities
In 2019, we renewed our syndicated credit agreement giving us access to a $1.25 billion committed credit facility. The agreement is fully committed, expiring in 2023. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. This credit facility has been made available for general corporate purposes including financing ongoing working capital requirements, providing financing for construction capital, growth opportunities and for repaying outstanding borrowings.
On July 24, 2017, TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500-million committed credit facility. The credit agreement is fully committed, and in the second quarter of 2019 was amended from $500 million to $700 million and extended to 2023. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. For further information please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Long-Term Debt
The long-term debt of the Corporation consists of $251 million face value of debentures outstanding, which bear interest at fixed rates ranging from 6.9 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030. In addition, we have US$700 million face value in senior notes outstanding that bear interest at fixed rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040. For further information please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
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Exchangeable Securities
On March 22, 2019, the Corporation entered into a definitive Investment Agreement, whereby Brookfield agreed to invest $750 million in the Corporation through the purchase of Exchangeable Securities, which are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Hydro Assets’ future-adjusted EBITDA, as described above. The Exchangeable Securities were issued in two tranches, with the first having occurred on May 1, 2019 consisting of $350 million of 7 per cent unsecured subordinated debentures due May 1, 2039 and on Oct. 30, 2020 the second and final close consisting of $400 million of a new series of redeemable, retractable first preferred shares. The Investment Agreement, together with an Exchange and Option Agreement (the "E&O Agreement") entered into by the parties concurrently with the closing of the first tranche of the investment, gives Brookfield the Exchange Right of the outstanding exchangeable securities into up to a maximum 49 per cent equity ownership interest in TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The Investment Agreement and the E&O Agreement also give TransAlta the right to redeem the Exchangeable Securities at any time after Dec. 31, 2028, subject to certain terms and conditions, if Brookfield chooses not to exercise its Option to Exchange. See "—Investment Agreement and E&O Agreement" below.
Investment Agreement and E&O Agreement
The following description of certain provisions of the Investment Agreement and the E&O is a summary only, is not comprehensive and is qualified in its entirety by reference to the full text of each of the Investment Agreement and E&O Agreement, copies of which can be found on SEDAR under our profile at www.sedar.com and on EDGAR under our profile at www.sec.gov.
In connection with the Investment Agreement, Brookfield has committed to purchase common shares of the Corporation on the open market over a period of 24 months following the Initial Funding Date, being May 1, 2019, to its total share ownership to not less than 9 per cent, subject to certain exceptions and provided that the Brookfield is not obliged to purchase common shares at a price greater than $10 per share. This increase in shareholdings further aligns the interests of Brookfield and TransAlta. Pursuant to the Investment Agreement, Brookfield is entitled to nominate two individuals on its slate of directors for election at the Corporation’s Annual meetings of shareholders.
The Investment Agreement contains certain lock-up provisions that restrict Brookfield or its affiliates’ ability to transfer their TransAlta common shares during a period that commenced on May 1, 2019, and terminates on Dec. 31, 2023 (the “Lock-Up”). The Lock-Up contains customary exceptions, including an exception for transfers of common shares by investment funds managed by or affiliated with Brookfield undertaken in accordance with the investment funds’ fund requirements.
The Investment Agreement contemplates that the Exchangeable Securities will be a long-term investment and therefore may not be transferred except by Brookfield to one of its affiliates. Brookfield has agreed to be the sole representative of all of its permitted transferees for the purpose of the Investment Agreement.
The Investment Agreement includes certain standstill commitments by the Brookfield (the “Standstill”), with customary exceptions, which will be in effect for three years starting from May 1, 2019 (the “Standstill Period”). Among other things, the Standstill prohibits the Brookfield from acquiring an ownership interest in the Corporation above 19.9 per cent of the common shares. During the Standstill Period, Brookfield has also agreed that it will: (a) vote in favour of each director nominated by the Board; (b) vote against any shareholder nomination for directors that is not approved by the Board; (c) vote against any proposal or resolution to remove any Board member; and (d) vote in accordance with any recommendations by the Board on all other proposals. Certain Standstill provisions extend beyond the Standstill Period so long as Brookfield has nominees on the Board.
In accordance with the terms of the Investment Agreement, TransAlta has formed a Hydro Assets Operating Committee consisting of two representatives from Brookfield and two representatives from TransAlta to provide advice and recommendations in connection with the operation, and maximizing the value, of the Alberta Hydro Assets. In connection with this, the Corporation has committed to pay Brookfield an annual hydro fee of $1.5 million for six years commencing on May 1, 2019.
Registration Rights Agreement
The following description of certain provisions of the registration rights agreement entered into between Eagle Hydro II (an affiliate of Brookfield) and the Corporation on May 1, 2019 (the “Registration Rights Agreement”) is a summary only, is not comprehensive and is qualified in its entirety by reference to the full text of the Registration Rights Agreement, a copy of which can be found on SEDAR under our profile at www.sedar.com.
The Registration Rights Agreement provides that Eagle Hydro II and any affiliate of Brookfield that becomes party to the Registration Rights Agreement (each a “Holder”) may, at any time and from time to time, make a written request (a “Demand Registration”) to the Corporation to file a Prospectus Supplement with the securities commissions or similar

authorities in each of the provinces of Canada in respect of the distribution of all or part of the Common Shares then held by the Holder (“Registrable Securities”), subject to certain restrictions set forth in the Registration Rights Agreement. Upon receipt by the Corporation of a Demand Registration, the Corporation will promptly file a Prospectus Supplement in order to permit the offer and sale or other disposition or distribution in Canada of all or any portion of the Registrable Securities held, directly or indirectly, by the Holder (a “Demand Offering”). The Corporation will not be obligated to effect: (a) more than three Demand Offerings in total during the term of the Registration Rights Agreement; or (b) a Demand Offering if the Registrable Securities have an aggregate market price of less than $50 million.
If at any time the Corporation proposes to file a prospectus supplement with respect to the distribution of any TransAlta common shares to the public, then the Corporation will give notice of the proposed distribution to each Holder not less than five business days in advance of the anticipated filing date of the prospectus supplement (or, in the case of a “bought deal” or another public offering that is not expected to include a road show, such notice as is practicable under the circumstances), which notice will offer each Holder the opportunity to qualify for distribution such number of Registrable Securities as such Holder may request. The Corporation will use commercially reasonable efforts to include in such Prospectus Supplement such Registrable Securities (a “Piggy Back Offering”), unless the Corporation’s managing underwriter or underwriters determines, in good faith, that including such Registrable Securities in the distribution would, in their opinion, adversely affect the Corporation’s distribution or sales price of the securities being offered by the Corporation.
The Demand Offerings and Piggy Back Offerings are subject to various conditions and limitations. The Corporation is entitled to defer any Demand Offering in certain circumstances, including during a regular annual and quarterly blackout period in respect of the release of its financial results.
The Registration Rights Agreement includes provisions providing for each of the Corporation and the Holders to indemnify each other for losses or claims caused by the applicable party’s inclusion of a misrepresentation in disclosure included in any prospectus and for breaches of applicable securities laws.
In the case of a prospectus supplement filed in connection with a Demand Offering or Piggy Back Offering, the Corporation will pay all applicable fees and expenses incident to the Corporation’s performance of, or compliance with, the terms of such offering, provided that in the event any Registrable Securities are freely tradeable at the time that the Corporation receives the offering request, the Corporation and the Holders will be jointly and severally responsible for the proportionate share of registration fees and expenses of any Holders based on the total offering price of the freely tradeable securities sold by the Holders to the total offering price of all the Securities sold by the Corporation in such offering. The Corporation and the Holders will be jointly and severally responsible for paying all selling expenses (including fees or commissions payable to an underwriter, investment banker, manager or agent and any transfer taxes attributable to the sale of Registrable Securities) with respect to Registrable Securities sold by the Holders and the Corporation will pay all selling expenses with respect to any Securities sold for the account of the Corporation. The Corporation and the Holders will be solely responsible on a joint and several basis for all out-of-pocket expenses incurred by any Holders in connection with a Demand Offering or Piggy Back Offering.
If a Holder ceases to be affiliated with the Corporation, the Holder will cease to have any rights or obligations under the Registration Rights Agreement. The Registration Rights Agreement will terminate when Brookfield together with its affiliates beneficially own in the aggregate less than three per cent of the issued and outstanding common shares.
Additional details about the Brookfield Investment can be found in our material change report dated March 26, 2019, available electronically on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. Copies of the Investment Agreement, together with copies of the exchangeable debenture, the E&O Agreement and the Registration Rights Agreement are also available on SEDAR and on EDGAR. Shareholders are encouraged to read these documents in their entirety.
Non-Recourse Debt
The Corporation has non-recourse debt outstanding in an amount equal to approximately $1,858 million face value, which is represented by bonds and debentures that bear interest at rates ranging from 2.95 per cent to 4.51 per cent and have maturity dates ranging from 2028 to 2042. For further information please see Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Tax Equity
In December 2019, coinciding with Big Level and Antrim wind projects achieving commercial operation, TransAlta received funding of approximately US$126 million from a tax equity partner. In December 2020, coinciding with the commercial operation of the Skookumchuck wind facility, a total of approximately US$121 million was raised from a tax equity partner in respect of the Skookumchuck project entity, which had the effect of lowering the cost of TransAlta's 49% investment in the Skookumchuck wind facility from approximately US$125 million to approximately US$66 million.

The Corporation also assumed US$24 million in tax equity financing as part of the acquisition of the Lakeswind wind facility in 2015. Under International Financial Reporting Standards tax equity financings are included as debt in our consolidated financial statements. For further information on tax equity please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Restrictions on Debt
The syndicated credit facilities include a number of customary covenants and restrictions in order to maintain access to the funding commitments. Non-recourse bonds are subject to customary financing conditions and covenants that may restrict the Corporation's ability to access funds generated by the facilities' operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution.
Credit Ratings
Credit ratings provide information relating to our financing costs, liquidity and operations and affect our ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows our commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to our financial results and provides us with better access to capital markets through commodity and credit cycles. We remain focused on strengthening our financial position and cash flow coverage ratios to ensure a strong balance sheet is maintained and sufficient financial capital is available. Our credit ratings as of Dec. 31, 2020, are as follows:

| DBRS | Moody's | S&P
Issuer Rating | BBB (low) | Not Applicable | BB+
Corporate Family Rating | Not Applicable | Ba1 | Not Applicable
Preferred Shares | Pfd-3 (low)(1) | Not Applicable | P-4(High)
Unsecured Debt/MTNs | BBB (low) | Ba1/LGD4 | BB+
Rating Outlook | Stable | Stable | Stable

Note:
(1) The outstanding Preferred Shares all have the same rating.
In 2020, Moody’s reaffirmed its issuer rating of Ba1 and revised its rating outlook to stable from positive. During 2020, DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook. Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating to BB+ with a stable outlook. In 2019, we decided not to renew our rating services with Fitch and the active rating from Fitch expired on Jan. 31, 2020.
DBRS
DBRS Corporate rating analysis begins with an evaluation of the fundamental creditworthiness of the issuer, which is reflected in an "issuer rating." Issuer ratings address the overall credit strength of the issuer. Unlike ratings on individual securities or classes of securities, issuer ratings are based on the entity itself and do not include consideration for security or ranking. Ratings that apply to actual securities (secured or unsecured) may be higher, lower or equal to the issuer rating for a given entity. As of Dec. 31, 2020, our issuer rating was BBB (low) (stable) from DBRS. A BBB rating is the fourth highest out of 10 categories.
The DBRS preferred share rating scale is used in the Canadian securities market and is meant to give an indication of the risk that a borrower will not fulfil its full obligations in a timely manner, with respect to both dividend and principal commitments. Every DBRS rating is based on quantitative and qualitative considerations relevant to the borrowing entity. Each rating category is denoted by the subcategories "high" and "low." The absence of either a "high" or "low" designation indicates the rating is in the middle of the category. Preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Each of the Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares have been rated Pfd-3 (low) (stable) by DBRS. The Pfd-3 rating is the third highest out of six categories.
The DBRS long-term rating scale provides an opinion on the risk of default, which is the risk that an issuer will fail to satisfy its financial obligations in accordance with the terms under which an obligation has been issued. Ratings are based on quantitative and qualitative considerations relevant to the issuer, and the relative ranking of claims. All rating
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categories other than AAA and D also contain subcategories "(high)" and "(low)". The absence of either a "(high)" or "(low)" designation indicates the rating is in the middle of the category. Debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. As of Dec. 31, 2020, our senior unsecured long-term debt is rated BBB (low) (stable) by DBRS. The BBB rating category is the fourth highest of 10 categories for long-term obligations.
Moody's
Moody's Corporate Family Ratings (CFRs) are long-term ratings that reflect the relative likelihood of a default on a corporate family's debt and debt-like obligations and the expected financial loss suffered in the event of default. A CFR is assigned to a corporate family as if it had a single class of debt and a single consolidated legal entity structure. A CFR does not reference an obligation or class of debt and thus does not reflect priority of claim. As at Dec. 31, 2020, our Corporate Family Rating was Ba1 with a stable outlook. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. Moody's appends the numerical modifiers 1, 2, and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. The Ba rating category is the fifth highest rating out of nine rating categories.
Moody's long-term ratings are assigned to issuers or obligations with an original maturity of one year or more and reflect both on the likelihood of a default on contractually promised payments and the expected financial loss suffered in the event of default. As of Dec. 31, 2020, our senior unsecured long-term debt is rated Ba1 / LGD4 by Moody's. The Ba rating category is the fifth-highest rating out of nine rating categories. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk.
Moody's Loss Given Default (LGD) assessments are opinions about expected loss given default expressed as a per cent of principal and accrued interest at the resolution of the default. One of the six LGD assessments are assigned to individual loan, bond, and preferred stock issues. The firm-wide or enterprise expected LGD rate generally approximates a weighted average of the expected LGD rates on the firm's liabilities (excluding preferred stock), where the weights equal each obligation's expected share of the total liabilities at default. As of Dec. 31, 2020, our LGD assessment from Moody's was LGD4 which represents a loss range of greater than or equal to 50 per cent and less than 70 per cent. LGD4 is the fourth-highest assessment category out six categories.
Standard & Poor's
A Standard & Poor's issuer credit rating is a forward-looking opinion about an obligor's overall creditworthiness. This opinion focuses on the obligor's capacity and willingness to meet its financial commitments as they come due. It does not apply to any specific financial obligation, as it does not take into account the nature of and provisions of the obligation, its standing in bankruptcy or liquidation, statutory preferences, or the legality and enforceability of the obligation. As at Dec. 31, 2020, our issuer credit rating was BB+ with a stable outlook with S&P. This is the fifth highest of 11 ratings categories. Although less vulnerable than other speculative issuers, an obligor rated BB is regarded as having a degree of speculative characteristics. When faced with uncertainties or challenges in the business, financial, or economic environment, entities rated ‘BB’ may in-turn face challenges meeting their financial commitments. The ratings from 'AA' to 'CCC' may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.
A Standard & Poor's issue credit rating is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion reflects Standard & Poor's view of the obligor's capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. This is the fifth highest of 11 ratings categories. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.
The Standard & Poor's Canadian preferred share rating scale serves issuers, investors, and intermediaries in the Canadian financial markets by expressing preferred share ratings (determined in accordance with global rating criteria) in terms of rating symbols that have been actively used in the Canadian market over a number of years. A Standard & Poor's preferred share rating on the Canadian scale is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market, relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on the global debt rating scale of Standard & Poor's. Each of our outstanding Preferred Shares Series have been rated P-4(High) by S&P. The P-4(High) rating is the fourth highest of eight categories. A P-4(High) rating corresponds to a B+ rating on the global preferred share rating scale.
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Obligors rated BB, B, CCC, and CC are regarded as having significant speculative characteristics, of which BB indicates the least degree of speculation and CC the highest. While such obligors will likely have some quality and protective characteristics, these may be outweighed by large uncertainties or major exposures to adverse conditions. An obligor rated 'B' is less vulnerable in the near term than other lower-rated obligors. However, it faces major ongoing uncertainties and exposure to adverse business, financial, or economic conditions which could lead to the obligor's inadequate capacity to meet its financial commitments.
We are focused on maintaining a strong financial position and cash flow coverage ratios to support our business. Our available credit facilities, funds from operations and debt financing options provide us with financial flexibility. As a result, we can be selective as to if and when we go to the capital markets for funding.
Note Regarding Credit Ratings
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. The credit ratings accorded to our outstanding securities by DBRS, Moody's and Standard & Poor's as applicable, are not recommendations to purchase, hold or sell such securities. There is no assurance that the ratings will remain in effect for any given period or that a rating will not be revised or withdrawn entirely by DBRS, Moody's or Standard & Poor's in the future if, in its judgement, circumstances so warrant.
We have paid fees for rating services to DBRS, Moody's, Standard & Poor's and Fitch during the last two years. We have also paid fees to S&P, DBRS and Kroll Bond Rating Agency for certain other services provided to the Corporation during the last two years.
Dividends
Common Shares
Dividends on our common shares are paid at the discretion of the Board. In determining the payment and level of future dividends, the Board considers our financial performance, results of operations, cash flow and needs, with respect to financing our ongoing operations and growth, balanced against returning capital to shareholders. The Board continues to focus on building sustainable earnings and cash flow growth.
TransAlta has declared and paid the following dividends per share on its outstanding common shares for the past three years:

Period |  | Dividend per Common Share
2018 | First Quarter Second Quarter Third Quarter Fourth Quarter | $0.04 $0.04 $0.04 $0.04
2019 | First Quarter Second Quarter Third Quarter Fourth Quarter | $0.04 $0.04 $0.04 $0.04
2020 | First Quarter Second Quarter Third Quarter Fourth Quarter | $0.04 $0.0425 $0.0425 $0.0425
2021 | First Quarter | $0.045

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Preferred Shares
TransAlta has declared and paid the following dividends per share on its outstanding preferred shares for the past three years:
Series A Shares

Period |  | Dividend per Series A Share
2018 | First Quarter | $0.16931
| Second Quarter | $0.16931
| Third Quarter | $0.16931
| Fourth Quarter | $0.16931
2019 | First Quarter | $0.16931
| Second Quarter | $0.16931
| Third Quarter | $0.16931
| Fourth Quarter | $0.16931
2020 | First Quarter | $0.16931
| Second Quarter | $0.16931
| Third Quarter | $0.16931
| Fourth Quarter | $0.16931
2021 | First Quarter | $0.16931

Series B Shares

Period |  | Dividend per Series B Share
2018 | First Quarter | $0.15651
| Second Quarter | $0.15645
| Third Quarter | $0.16125
| Fourth Quarter | $0.17467
2019 | First Quarter | $0.17889
| Second Quarter | $0.19951
| Third Quarter | $0.20984
| Fourth Quarter | $0.22301
2020 | First Quarter | $0.22949
| Second Quarter | $0.22800
| Third Quarter | $0.14359
| Fourth Quarter | $0.13693
2021 | First Quarter | $0.13186

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Series C Shares

Period |  | Dividend per Series C Share
2018 | First Quarter | $0.2875
| Second Quarter | $0.2875
| Third Quarter | $0.25169
| Fourth Quarter | $0.25169
2019 | First Quarter | $0.25169
| Second Quarter | $0.25169
| Third Quarter | $0.25169
| Fourth Quarter | $0.25169
2020 | First Quarter | $0.25169
| Second Quarter | $0.25169
| Third Quarter | $0.25169
| Fourth Quarter | $0.25169
2021 | First Quarter | $0.25169

Series E Shares

Period |  | Dividend per Series E Share
2018 | First Quarter | $0.3125
| Second Quarter | $0.3125
| Third Quarter | $0.3125
| Fourth Quarter | $0.32463
2019 | First Quarter | $0.32463
| Second Quarter | $0.32463
| Third Quarter | $0.32463
| Fourth Quarter | $0.32463
2020 | First Quarter | $0.32463
| Second Quarter | $0.32463
| Third Quarter | $0.32463
| Fourth Quarter | $0.32463
2021 | First Quarter | $0.32463

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Series G Shares

Period |  | Dividend per Series G Share
2018 | First Quarter | $0.33125
| Second Quarter | $0.33125
| Third Quarter | $0.33125
| Fourth Quarter | $0.33125
2019 | First Quarter | $0.33125
| Second Quarter | $0.33125
| Third Quarter | $0.33125
| Fourth Quarter | $0.31175
2020 | First Quarter | $0.31175
| Second Quarter | $0.31175
| Third Quarter | $0.31175
| Fourth Quarter | $0.31175
2021 | First Quarter | $0.31175

Series I Shares
TransAlta also declared an aggregate cash dividend of $4,743,169.40 in respect of the issued and outstanding Series I Shares for the period starting from and including Oct. 30, 2020 up to but excluding Dec. 31, 2020, which was paid on March 1, 2021.
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Market for Securities
Common Shares
Our common shares are listed on the TSX under the symbol "TA" and the New York Stock Exchange (the "NYSE") under the symbol "TAC." The following table sets forth the reported high and low trading prices and trading volumes of our common shares as reported by the TSX for the periods indicated:

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 10.74 | 5.32 | 45,631,306
April | 8.58 | 6.86 | 17,856,819
May | 8.55 | 7.37 | 15,568,382
June | 9.00 | 7.73 | 13,284,705
July | 8.87 | 7.93 | 8,080,666
August | 8.91 | 8.32 | 10,913,070
September | 8.49 | 7.67 | 15,566,902
October | 8.74 | 7.85 | 10,519,344
November | 9.09 | 7.96 | 13,998,923
December | 9.77 | 8.75 | 13,100,333
2021 |  |  |
January | 11.57 | 9.57 | 6,986,031
February | 12.34 | 10.97 | 15,152,046
March 1 | 11.30 | 11.12 | 813,152

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Preferred Shares
Series A Shares
Our Series A Shares are listed on the TSX under the symbol "TA.PR.D".

Date of Issuance | Number of Securities (2) | Issue Price per Security | Description of Transaction
Dec. 10, 2010(1) | 12,000,000 Series A Shares | $25.00 | Public Offering

Notes:
(1)Series A Shares were issued pursuant to a public offering by way of a prospectus supplement dated Dec. 3, 2010, to a short form base shelf prospectus dated Oct. 19, 2009.
(2)On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 1, 2021, we announced that we will not redeem any of our Series A Shares. As a result, holders of the Series A Shares will have until March 16, 2021 in order to exercise their right to convert all or any portion of the Series A Shares into Series B Shares, subject to the share terms

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 10.51 | 6.48 | 501,198
April | 7.98 | 8.15 | 380,878
May | 8.21 | 7.80 | 159,953
June | 8.89 | 7.78 | 218,448
July | 9.32 | 8.20 | 67,513
August | 9.35 | 8.80 | 69,279
September | 9.33 | 8.75 | 168,784
October | 9.06 | 8.55 | 159,637
November | 10.29 | 8.61 | 211,603
December | 10.99 | 9.83 | 233,317
2021 |  |  |
January | 12.40 | 10.47 | 316,112
February | 11.91 | 10.20 | 470,997
March 1 | 10.46 | 10.21 | 8,256

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Series B Shares
Our Series B Shares are listed on the TSX under the symbol "TA.PR.E".

Date of Issuance | Number of Securities | Issue Price per Security | Description of Transaction
March 31, 2016(1) | 1,824,620 Series B Shares | N/A | Conversion of Series A Shares

Note:
(1)On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 1, 2021, we announced that we will not redeem any of our Series B Shares. As a result, holders of the Series B Shares will have until March 16, 2021 in order to exercise their right to convert all or any portion of the Series B Shares into Series A Shares, subject to the share terms.

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 11.10 | 7.22 | 63,886
April | 9.25 | 7.70 | 132,206
May | 8.70 | 8.00 | 71,932
June | 8.70 | 7.90 | 71,216
July | 8.90 | 8.13 | 83,830
August | 9.26 | 8.60 | 30,000
September | 9.25 | 8.53 | 114,250
October | 9.00 | 8.51 | 25,852
November | 10.11 | 8.70 | 45,236
December | 10.75 | 9.81 | 45,766
2021 |  |  |
January | 12.35 | 10.27 | 82,249
February | 12.35 | 9.57 | 40,391
March 1 | 11.10 | 11.10 | 100

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Series C Shares
Our Series C Shares are listed on the TSX under the symbol "TA.PR.F".

Date of Issuance | Number of Securities | Issue Price per Security | Description of Transaction
Nov. 30, 2011(1) | 11,000,000 Series C Shares | $25.00 | Public Offering

Note:
(1) Series C Shares were issued pursuant to a public offering by way of a prospectus supplement dated Nov. 23, 2011 to a short form base shelf prospectus dated Nov. 15, 2011.

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 13.70 | 8.51 | 253,494
April | 10.81 | 9.56 | 493,216
May | 10.87 | 10.34 | 192,767
June | 12.18 | 10.40 | 184,950
July | 11.97 | 10.92 | 163,722
August | 12.82 | 11.65 | 102,358
September | 12.94 | 12.30 | 143,238
October | 12.76 | 12.21 | 183,505
November | 14.20 | 12.31 | 142,357
December | 15.03 | 13.71 | 131,024
2021 |  |  |
January | 16.01 | 14.99 | 261,542
February | 15.19 | 13.51 | 105,334
March 1 | 13.70 | 13.35 | 16,500

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Series E Shares
Our Series E Shares are listed on the TSX under the symbol "TA.PR.H".

Date of Issuance | Number of Securities | Issue Price per Security | Description of Transaction
Aug. 10, 2012(1) | 9,000,000 Series E Shares | $25.00 | Public Offering

Note:
(1) Series E Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 3, 2012 to a short form base shelf prospectus dated Nov. 15, 2011.

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 16.16 | 9.90 | 410,060
April | 13.13 | 11.70 | 385,601
May | 13.14 | 12.59 | 110,397
June | 14.25 | 12.64 | 252,694
July | 14.18 | 13.22 | 137,272
August | 14.95 | 13.87 | 106,456
September | 15.42 | 14.60 | 131,659
October | 15.02 | 14.43 | 115,584
November | 17.01 | 14.51 | 119,557
December | 17.99 | 16.45 | 291,326
2021 |  |  |
January | 18.93 | 17.88 | 339,587
February | 17.45 | 15.72 | 162,972
March 1 | 16.16 | 15.85 | 12,600

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Series G Shares
Our Series G Shares are listed on the TSX under the symbol "TA.PR.J".

Date of Issuance | Number of Securities | Issue Price per Security | Description of Transaction
Aug. 15, 2014(1) | 6,600,000 Series G Shares | $25.00 | Public Offering

Note:
(1) Series G Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 8, 2014 to a short form base shelf prospectus dated Dec. 9, 2013.

| Price ($) |
Month | High | Low | Volume
2020 |  |  |
March | 16.65 | 10.70 | 201,696
April | 14.77 | 12.05 | 252,234
May | 14.58 | 14.10 | 59,889
June | 15.45 | 14.01 | 89,643
July | 15.25 | 13.96 | 162,358
August | 16.50 | 15.30 | 38,207
September | 16.29 | 15.50 | 75,321
October | 16.00 | 15.51 | 104,703
November | 17.85 | 15.61 | 84,339
December | 18.99 | 17.38 | 90,111
2021 |  |  |
January | 20.00 | 18.93 | 98,474
February | 18.10 | 16.26 | 141,552
March 1 | 16.52 | 16.35 | 1,600

Series I Shares
On Oct. 30, 2020, the Corporation issued 400,000 redeemable first preferred shares, Series I ("Series I Shares"), at a price of $1,000 per Series I Share, for aggregate proceeds of $400,000,000. The Series I Shares were issued to Brookfield under the Investment Agreement and are not listed or quoted on a marketplace.
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Directors and Officers
The name, province or state and country of residence of each of our directors as at Dec. 31, 2020, their respective position and office and their respective principal occupation during the five preceding years, are set out below. The year in which each director was appointed to serve on the Board is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed.

Name, Province (State) and Country of Residence | Year First Became Director | Principal Occupation
Rona H. Ambrose Alberta, Canada | 2017 | The Honourable Rona Ambrose is Chair of the Governance, Safety and Sustainability Committee. She is a national leader, former Leader of Canada's Official Opposition in the House of Commons and former leader of the Conservative Party of Canada. As a key member of the federal cabinet for a decade, Ms. Ambrose solved problems as a minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board for several years and Chair of the cabinet committee for public safety, justice and Aboriginal issues. As the former environment minister responsible for the GHG regulatory regime in place across several industrial sectors, she understands the challenges facing the fossil fuel industry. Ms. Ambrose was personally responsible for the development of several federal policies, ranging from industrial strategies in military procurement to health innovation to improvements to sexual assault laws. Ms. Ambrose is a passionate advocate for women in Canada and around the world and led the global movement to create the "International Day of the Girl" at the United Nations. She was also responsible for ensuring that Aboriginal women in Canada were finally granted equal matrimonial rights. She successfully fought for the creation of a Canadian refugee program to bring Yazidi women and girls who have been sexually enslaved by ISIS to safety in Canada. Ms. Ambrose is the Deputy Chairwoman of TD Securities. She is a Global Fellow at the Wilson Centre Canada Institute in Washington, DC and serves on the advisory board of the Canadian Global Affairs Institute. Ms. Ambrose is also a director of Manulife Financial Corporation, Coril Holdings Ltd. and Andlauer Healthcare Group. She has a BA from the University of Victoria and an MA from the University of Alberta. She is also a graduate of the Harvard Kennedy School of Government Senior Leaders Program. Ms. Ambrose has an extensive track record of strong leadership acquired through a wide range of experience at the most senior levels of the Canadian government. {
John P. Dielwart Alberta, Canada | 2014 | Mr. Dielwart is the Chair of the Board. Mr. Dielwart was formerly Chief Executive Officer of ARC Resources Ltd., which owns and operates oil and gas properties in Western Canada. He oversaw the growth of ARC Resources Ltd. from start-up in 1996 to a company with a total capitalization of approximately $10 billion at the time of his retirement. After his retirement from ARC Resources Ltd. on Jan. 1, 2013, Mr. Dielwart re-joined ARC Financial Corp. as Vice-Chairman and Partner. ARC Financial is Canada's leading energy-focused private equity manager. In 2020, Mr. Dielwart resigned from the board but remained as Partner and member of ARC Financial's Investment and Governance committees, and currently represents ARC Financial on the board of Aspenleaf Energy Limited. Mr. Dielwart has a Bachelor of Science with distinction (civil engineering) degree from the University of Calgary. He is a member of the Association of Professional Engineers and Geoscientists of Alberta and is a past Chairman of the Board of Governors of the Canadian Association of Petroleum Engineers . In 2015, Mr. Dielwart was inducted into the Calgary Business Hall of Fame and in 2018 he received the Oil and Gas Council's Canadian Lifetime Achievement Award. He is also a director of Crescent Point Energy Corp.

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Name, Province (State) and Country of Residence | Year First Became Director | Principal Occupation
Dawn L. Farrell Alberta, Canada | 2012 | Mrs. Farrell became President and Chief Executive Officer of TransAlta Corporation on Jan. 2, 2012. Prior to her appointment, she served as Chief Operating Officer from 2009 to 2011. Mrs. Farrell has over 35 years of experience in the electricity industry, with roles at TransAlta and BC Hydro. She has served as Executive Vice-President, Commercial Operations and Development; Executive Vice-President, Corporate Development; Executive Vice-President, Independent Power Projects; and Vice-President, Energy Marketing and IPP Development at TransAlta Corporation. From 2003 to 2006, Mrs. Farrell served as Executive Vice-President, Generation at BC Hydro. From 2006 to 2007, she served as BC Hydro’s Executive Vice-President Engineering, Aboriginal Relations and Generation. Mrs. Farrell sits on the board of directors of The Chemours Company, an NYSE-listed chemical company, and the Business Council of Alberta. She is also a member of the Trilateral Commission and the Business Council of Canada, and is Chancellor of Mount Royal University. Her past board appointments include The Conference Board of Canada, the Business Council of Canada, the Calgary Stampede, the Mount Royal College Board of Governors, Fording Coal Income Fund, New Relationship Trust Fund, and Mount Royal College Foundation. Mrs. Farrell holds a Bachelor of Commerce with a major in finance and a Master's degree in economics from the University of Calgary. She has also attended the Advanced Management Program at Harvard University. Mrs. Farrell will retire as President and Chief Executive Officer and as a member of the Board of Directors on March 31, 2021.
Alan J. Fohrer California, U.S.A. | 2013 | Mr. Fohrer was Chairman and Chief Executive Officer of Southern California Edison Company ("SCE"), a subsidiary of Edison International ("Edison") and one of the largest electric utilities in the United States. He was elected Chief Executive Officer in 2002 and Chairman in 2007. In 2000, Mr. Fohrer was elected as President and Chief Executive Officer of Edison Mission Energy ("EME"), a subsidiary of Edison that owns and operates independent power facilities. During his tenure at EME, Mr. Fohrer restructured a number of the international projects, which enhanced the value of the assets sold in subsequent years. Mr. Fohrer also served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE from 1995 to 1999. After 37 years with Edison, Mr. Fohrer retired in December 2010. He currently sits on the boards of PNM Resources, Inc., a publicly-held energy holding company, and Blue Shield of California, a non-profit health insurance provider. Mr. Fohrer has served on boards of directors of the Institute of Nuclear Power Operations, the California Chamber of Commerce, Duratek, Inc., and Osmose Utilities Services, Inc., MWH, Inc. and Synagro, a private waste management company. He is also a member of the Viterbi School of Engineering Board of Councilors for the University of Southern California and Chair of the California Science Center Foundation. Mr. Fohrer holds a Master of Science in civil engineering from the University of Southern California, Los Angeles, as well as a Master of Business Administration from California State University in Los Angeles.
Harry Goldgut Ontario, Canada | 2019 | Mr. Goldgut is Vice Chair of Brookfield Asset Management's Renewable Group and Brookfield's Infrastructure Group and provides strategic advice related to Brookfield's open-end Infrastructure Fund. Mr. Goldgut was the CEO or Co-CEO and Chairman of Brookfield Renewable Power Inc., from 2000 to 2008, and thereafter, until 2015, he was Chairman of Brookfield's Power and Utilities Group. From 2015 to 2018, he served as Executive Chairman of Brookfield's Infrastructure and Power Groups. Mr. Goldgut joined Brookfield in 1997 and led the expansion of Brookfield's renewable power and utilities operations. He has had primary responsibility for strategic initiatives, acquisitions and senior regulatory relationships. He was responsible for the acquisition of the majority of Brookfield's renewable power assets. Mr. Goldgut also played a role in the restructuring of the electricity industry in Ontario as a member of several governmental committees, including the Electricity Market Design Committee, the Minister of Energy's Advisory Committee, the Clean Energy Task Force, the Ontario Energy Board Chair's Advisory Roundtable and the Ontario Independent Electricity Operator CEO Roundtable on Market Renewal. Mr. Goldgut also serves on the Boards of Directors of Isagen S.A. ESP, the third- largest power generation company in Colombia; and the Princess Margaret Cancer Foundation. Mr. Goldgut attended the University of Toronto and holds an LL.B from York University's Osgoode Hall Law School.
Richard Legault Quebec, Canada | 2019 | Mr. Legault is Vice Chair of Brookfield's Renewable Group. Prior to his current role, Mr. Legault served as Chief Executive Officer of Brookfield Renewable Partners from 1999 to August 2015, during which time he led the growth of Brookfield's renewable power operations globally, helping to make Brookfield Renewable one of the world's largest publicly traded, pure-play renewable power portfolios. From 2015 to 2018, he served as Executive Chairman of the Brookfield Renewable Group. Mr. Legault was Chief Financial Officer of Brookfield Asset Management from 2000 to 2001, prior to which he held several senior positions in operations, finance, and corporate development with Brookfield's forest products operations. Serving at Brookfield for over 31 years, Mr. Legault has been described as instrumental in developing Brookfield's renewable business, which is well-established in North America, South America and Europe. Mr. Legault also serves on the Board of Directors of Westinghouse Electric Corporation, one of the largest nuclear technology and services companies globally, and serves as chair of its Risk Committee. Mr. Legault received a Bachelor of Accounting from the Université du Québec in Hull and is a member of the Chartered Professional Accountants of Canada (CPA, CA).

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Name, Province (State) and Country of Residence | Year First Became Director | Principal Occupation
Yakout Mansour California, U.S.A. | 2011 | Mr. Mansour is Chair of the Investment Performance Committee. Mr. Mansour has over 40 years of experience as both a professional engineer and executive in the electric utility business in Canada, the United States, and abroad. He retired as President and Chief Executive Officer of the California Independent System Operator Corporation ("CAISO") in 2011, a position he had held since 2005. CAISO is responsible for operating and controlling 80 per cent of the California electric grid, designing and operating the California electricity market, and for settlements of over $8 billion annually. Under Mr. Mansour's leadership, the California market structure was completely redesigned, and CAISO established the market and technical foundation to accommodate one of the most aggressive renewable portfolio standards in the world. Prior to that, Mr. Mansour served in senior executive roles at BC Hydro and the British Columbia Transmission Corporation where he was responsible for operation, asset management, and inter-utility affairs of the electric grid. In 2009, Mr. Mansour was named to the U.S. Department of Energy Electricity Advisory Committee as a vice chair. He also served on the various committees of the North American Electric Reliability Corporation and its predecessor organization, CEGRE, the Transmission Council of the Canadian Electricity Association, and the Board of Directors of the Electric Power Research Institute. A retired professional engineer and a Fellow of the Institute of Electrical and Electronics Engineers, Mr. Mansour has authored and co-authored numerous publications. He is recognized internationally in the field of power engineering and received several distinguished awards for his contributions to the industry. Mr. Mansour holds a Bachelor of Science in electrical engineering from the University of Alexandria (Egypt) and a Master of Science from the University of Calgary.. Mr. Mansour brings to the Corporation and the Board decades of experience in our industry in generation, transmission and energy competitive markets in both a regulated and deregulated market environment. His technical and operational expertise provide an important diversity of thought and perspective to the Board.
Georgia R. Nelson Washington, U.S.A. | 2014 | Ms. Nelson was President and Chief Executive Officer of PTI Resources, LLC, an independent consulting firm, from 2005 to 2019. Ms. Nelson had a 35-year career in the power generation industry, serving in various senior executive capacities for Edison International and its subsidiaries between 1971 and 2005. She was President of Midwest Generation Edison Mission Energy (EME), an independent power producer, from 1999 to her retirement in 2005 and General Manager of EME Americas, from 2002 to 2005. Ms. Nelson has extensive experience in electric and renewable energy operations, international business negotiations, environmental policy matters and human resources. Ms. Nelson is currently a director of Cummins Inc., Ball Corporation, and Sims Metal Management Ltd. She was a director of CH2MHILL Corporation, a privately-held company, until December 2017. Ms. Nelson is a past director of Nicor, Inc. Ms. Nelson was a member of the executive committee of the National Coal Council from 2000 to 2015, and served as Chair from 2006 to 2008. She serves on the advisory committee of the Center for Executive Women at Northwestern University. Ms. Nelson was named to the 2012 National Association of Corporate Directors ("NACO") Directorship 100. She is an NACO Board Fellow. Ms. Nelson holds a Bachelor of Science from Pepperdine University and a Master of Business Administration from the University of Southern California.
Beverlee F. Park British Columbia, Canada | 2015 | Ms. Park is the Chair of the Audit, Finance and Risk Committee of the Board as of April 19, 2018. She is also a director of SSR Mining Inc., a publicly-listed mining company, focused on the operation, development, exploration and acquisition of precious metals projects. Ms. Park was previously a member of the Board of Directors of Teekay LNG Partners, InTransit BC and BC Transmission Corp., where she had chaired the audit committees. Ms. Park has served on a wide range of not-for-profit boards over her career, including the University of British Columbia Board of Governors. Ms. Park was an executive of TimberWest Forest Corp. until her retirement in 2013. While at TimberWest she held several roles including Interim CEO, COO, President of the real estate division and Executive Vice President and CFO. Prior to being at TimberWest, Ms. Park was at BC Hydro and KPMG. Ms. Park holds a Bachelor of Commerce from McGill University, an MBA from Simon Fraser University Executive program and is a Fellow of the Chartered Professional Accountants of British Columbia (FCPA/FCA).
Bryan D. Pinney Alberta, Canada | 2018 | Mr. Pinney is Chair of the Human Resources Committee. He is currently the lead director for North American Construction Group Ltd., and a director of Sundial Growers Inc., a NASDAQ-listed company. Mr. Pinney was also the recent chair of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He is also a director of one private company. He is a Fellow of the Institute of Chartered Accountants, a Chartered Business Valuator and is a graduate of the Ivey Business School at the University of Western Ontario with an honours degree in Business Administration. He is also a graduate of the Canadian Institute of Corporate Directors. Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. Mr. Pinney was a partner with Deloitte LLP between 2002 and 2015. Mr. Pinney served as Calgary Managing Partner of Deloitte LLP from 2002 through 2007 and as National Managing Partner of Audit & Assurance from 2007 to 2011 and Vice-Chair until June 2015. Mr. Pinney was a past member of Deloitte LLP's Board of Directors and chair of the Finance and Audit Committee. Prior to joining Deloitte LLP, Mr. Pinney was a partner with Andersen LLP and served as Calgary Managing Partner from 1991 through May of 2002.

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Name, Province (State) and Country of Residence | Year First Became Director | Principal Occupation
Sandra R. Sharman Ontario, Canada | 2020 | Ms. Sandra Sharman leads the Human Resources, Communications, Marketing and Enterprise Real Estate teams at CIBC, supporting execution of business strategy, transforming to a purpose-driven bank and enabling a world-class culture. Ms. Sharman and her team are responsible for developing and delivering the Global Human Capital Strategy designed to challenge conventional thinking, drive business solutions and shape the culture of the bank. Her key areas of accountabilities also include workplace transformation, compensation and benefits, employee relations, policy and governance, talent management, marketing, corporate real estate, including the bank’s new global headquarters, CIBC Square and all aspects of internal and external communications and public affairs, including government relations and awards. A proven business leader with over 30 years of human resources and financial services experience in both Canada and the U.S., Ms. Sharman has played a lead role in shaping an inclusive and collaborative culture at CIBC, focused on empowering and enabling employees to reach their full potential. Ms. Sharman assumed the leadership of Human Resources at CIBC in 2014 and added accountability for communications and public affairs in 2017. Since then, her portfolio has expanded to encompass purpose, brand, marketing and most recently corporate real estate. Ms. Sharman earned her Masters of Business Administration at Dalhousie University.

Officers
The name, province or state and country of residence of each of our executive officers as at March 2, 2021, their respective position and office and their respective principal occupation are set out below.

Name | Principal Occupation | Residence
Dawn L. Farrell | President and Chief Executive Officer | Alberta, Canada
Jane N. Fedoretz | Executive Vice President, People, Talent & Transformation | Alberta, Canada
Brett M. Gellner | Chief Development Officer | Alberta, Canada
John H. Kousinioris | Chief Operating Officer | Alberta, Canada
Michael J. Novelli | Executive Vice-President, Generation | Alberta, Canada
Blain van Melle | Executive Vice-President, Alberta Business | Alberta, Canada
Kerry O'Reilly Wilks | Executive Vice President, Legal, Commercial & External Affairs | Alberta, Canada
Todd J. Stack | Executive Vice President, Finance & Chief Financial Officer | Alberta, Canada
Aron Willis | Executive Vice-President, Growth | Alberta, Canada

All of the executive officers of TransAlta have held their present principal occupation or position for the past five years, except for the following:
•On Feb. 4, 2021, the Corporation announced that Mrs. Farrell intends to retire as President and Chief Executive Officer effective March 31, 2021.
•Prior to August 2019, Mr. Gellner was Chief Investment and Strategy Officer of TransAlta. Prior to November 2018, Mr. Gellner was Interim Chief Financial Officer and Chief Strategy and Investment Officer of the Corporation. Prior to July 2018, Mr. Gellner was Chief Investment Officer of the Corporation. Prior to August 2013, Mr. Gellner was Chief Financial Officer of the Corporation. Mr .Gellner will retire as an officer of the Corporation on May 1, 2021. Mr. Gellner is expected to continue to serve as a non-independent director of TransAlta Renewables.
•Prior to February 2021, Ms. Fedoretz was Chief Talent & Transformation Officer of TransAlta. Prior to November 2018, Ms. Fedoretz was Counsel, Energy Group at Blake, Cassels & Graydon LLP.
•On Feb 4, 2021, the Corporation announced that Mr. Kousinioris will be appointed President and Chief Executive Officer on Apr. 1, 2021. Prior to August 2019, Mr. Kousinioris was Chief Growth Officer of TransAlta. Prior to July 2018, Mr. Kousinioris was Chief Legal and Compliance Officer and Corporate Secretary of the Corporation. Prior to October 2015, Mr. Kousinioris was Chief Legal and Compliance Officer of TransAlta. Prior to December 2012, Mr. Kousinioris was a Partner and co-head of the Corporate Commercial Group at Bennett Jones LLP, Barristers and Solicitors.
•Prior to February 2021, Ms. O'Reilly Wilks was Chief Officer, Legal, Regulatory & External Affairs of TransAlta. Prior to August 2019, Ms. O'Reilly Wilks was Chief Legal & Compliance Officer of TransAlta. Prior to November 2018, Ms. O'Reilly Wilks was Head of Legal, North Atlantic & UK, for Vale S.A. (Base Metal Business).
•Prior to February 2021, Mr. Stack was Chief Financial Officer of TransAlta. Prior to May 2019, Mr. Stack was Managing Director and Corporate Controller of TransAlta. Prior to February 2017, Mr. Stack was Managing
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Director and Treasurer of TransAlta. Prior to October 2015, Mr. Stack was Vice-President and Treasurer of TransAlta. Prior to November 2012, Mr. Stack was Treasurer of TransAlta.
•Prior to May 2020, Mr. Novelli was Chief Operating Officer of InterGen, a global independent power generation and energy development company. Prior to 2016, Mr. Novelli was Vice President and General Manager of InterGen. Prior to 2015, Mr. Novelli was Vice President, Global Operations and Engineering of InterGen.
As of March 3, 2021, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over less than one per cent of our outstanding common shares.
Interests of Management and Others in Material Transactions
No director or executive officer of TransAlta, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than 10 per cent of our common shares, and no associate or affiliate of any of them, has or has had any material interest, direct or indirect, in any transaction involving TransAlta within the three most recently completed financial years or to date in 2021 or in any proposed transactions that has materially affected or will materially affect us.
In connection with the Brookfield Investment, Mr. Richard Legault and Mr. Harry Goldgut were nominated by Brookfield and elected to the Board on April 26, 2019. See "Directors and Officers." Brookfield is also entitled to receive certain funding fees, management fees and interest and dividends on its $750-million investment. See "General Development of the Business – Three- Year History – Generation and Business Development – 2019 – Strategic Investment by Brookfield Renewable Partners", and "Ca p ital and Loan Structure – Investment Agreement and E&O Agreement."
Indebtedness of Directors, Executive Officers and Senior Officers
Since Jan. 1, 2020, there has been no indebtedness outstanding to TransAlta from any of our directors, executive officers, senior officers or associates of any such directors, nominees or senior officers.
Corporate Cease Trade Orders, Bankruptcies or Sanctions
Corporate Cease Trade Orders and Bankruptcies
No director, executive officer or controlling security holder of TransAlta Corporation is, as at the date of this Annual Information Form, or has been, within the past 10 years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:
•was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
•was subject to an event that resulted, after the person ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
•within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.
Personal Bankruptcies
No director, executive officer or controlling security holder of TransAlta Corporation has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person's assets.
Penalties or Sanctions
No director, executive officer or controlling security holder of TransAlta Corporation has:
•been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or
•been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.
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Material Contracts
Other than contracts entered into in the ordinary course of business, the Corporation believes that the following are material contracts, the particulars of which are disclosed elsewhere in this AIF, to which the Corporation or its subsidiaries are a party:
•Investment Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement"
•E&O Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement"
•Registration Rights Agreement - See "Capital Structure - Registration Rights Agreement"
•Off-Coal Agreement - See "Business of TransAlta - Alberta Thermal Business Segment - Off-Coal Agreement"
Conflicts of Interest
Circumstances may arise where members of the Board serve as directors or officers of corporations which are in competition to the interests of TransAlta. No assurances can be given that opportunities identified by such member of the Board will be provided to us. However, our policies provide that each director and executive officer must comply with the disclosure requirements of the CBCA regarding any material interest. If a declaration of material interest is made, the declaring director shall not vote on the matter if put to a vote of the Board. In addition, the declaring director and executive officer may be requested to recuse himself or herself from the meeting when such matter is being discussed.
Legal Proceedings and Regulatory Actions
TransAlta is occasionally named as a party in claims and legal proceedings that arise during the normal course of its business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that such claim may not have a material adverse effect on TransAlta. For further information, please refer to Note 35 of our audited consolidated financial statements for the year ended Dec. 31, 2019, which financial statements are incorporated by reference herein. See "Documents Incorporated by Reference."
FMG Disputes
The Corporation is currently engaged in a dispute with FMG as a result of FMG’s purported termination of the South Hedland PPA. TransAlta sued FMG, seeking payments of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. This matter has been rescheduled to proceed to trial beginning May 3, 2021, instead of June 15, 2020.
The Corporation had a second dispute involving FMG's claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claimed certain amounts relating to the condition of the facility while TransAlta claimed certain costs should be reimbursed. The dispute was settled and discontinued in the Supreme Court of Western Australia on Sept. 9, 2020.
Mangrove Complaint
On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice, naming TransAlta Corporation, the incumbent members of the Board of Directors of TransAlta Corporation on such date, and Brookfield BRP Holdings (Canada), as defendants. Mangrove is seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter has been rescheduled and the three-week trial will begin on April 19, 2021.
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Keephills 1 Stator Force Majeure Appeal
The Balancing Pool and ENMAX Energy Corporation ("ENMAX") are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench ("ABQB") dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal is scheduled to be heard on April 8, 2021. TransAlta believes that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.
Keephills 1 Superheater Force Majeure
Keephills Unit 1 was taken offline from March 17, 2015 to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta Generation Partnership claimed force majeure under the Keephills PPA. ENMAX, the PPA buyer under the PPA at the time, did not dispute the force majeure but the Balancing Pool did, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The Balancing Pool argued and won in the Courts that it has a right under the PPA to commence an arbitration, independent of the PPA buyer, ENMAX. An arbitration for this dispute has commenced and is set to be heard for seven days starting Dec. 6, 2021.
Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits
The Balancing Pool claims to be entitled to emissions performance credits ("EPCs"), valued at approximately $17 million per year, earned by the hydro facilities under the Carbon Competitiveness Incentive Regulation from 2018-2020. The dispute is based on the ownership of the EPCs as a result of a change-in-law provision under the Hydro PPA and that TransAlta is benefiting from the purported change in law. TransAlta has not received any benefit from the EPCs and has not recognized any benefit from the EPCs within its financial statements. TransAlta believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and will be likely set down for a hearing sometime in early 2022.
Sundance A Decommissioning
TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and the Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2021 or early 2022. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.
Direct Assigned Capital Deferral Account (“DACDA”) Application
AltaLink Management Ltd. ("AltaLink") filed an application before the AUC to recover its 2016-2018 DACDA costs (the "Proceeding") incurred for the 240 kV line upgrades project in the Edmonton region (the “Upgrades Project”). TransAlta is a secondary applicant in the Proceeding because it owns a portion of the 1043L Line located on Enoch Cree Nation Reserve that was a part of the Upgrades Project. AltaLink and TransAlta sought to have their costs ($91 million for AltaLink, and $22 million for TransAlta) approved by the AUC as reasonable and prudent. The Enoch Cree Nation and the Consumers Coalition of Alberta are registered participants in the Proceeding. The AUC rendered its decision in the Proceeding on Dec. 10, 2020 and disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta believes that the AUC made errors by disallowing 15 percent of its costs and therefore filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC. The court will be adjourned until the review and variance process is completed.
Line Loss Rule Proceeding
The Corporation has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed AESO to recalculate loss factors for 2006 to 2016 and issue a single invoice charging or crediting market participants for the difference in loss charges. The AESO submitted a review and variance application of this decision to implement a “pay-as-you-go” invoicing scheme rather than issue a single invoice. The AUC ruled on AESO’s request and approved a three-period invoice process (2006-2009, 2010-2013, and 2014-2016). The total liability for the loss charges was $25 million; however, due to payments made (and received) for the first two invoices, only $8 million of the total liability remains outstanding. The AESO issued the first invoice on Oct. 22, 2020 for $6 million which was paid prior to Dec. 30, 2020. The second invoice was issued on Dec. 21, 2020 for $11 million. The third invoice is expected in March 2021.
In November 2020, AESO sought direction from the AUC with respect to interest payments on the loss charges, and the AUC ruled in January 2021 that simple interest (rather than compound interest) would apply to the loss charges.
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Transfer Agent and Registrar
The transfer agent and registrar for our common shares and Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares is Computershare Investor Services Inc. Common shares are transferable in Vancouver, Calgary, Toronto, Montréal and Halifax. Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares are transferable in Calgary and Toronto. The transfer agent and registrar for our common shares in the United States is Computershare Trust Company at its principal office in Jersey City, New Jersey.
Interests of Experts
The Corporation's auditors are Ernst & Young LLP, Chartered Professional Accountants, 2200, 215 – 2nd Street, S.W., Calgary, Alberta, T2P 1M4.
Our auditors, Ernst & Young LLP, are independent with respect to TransAlta Corporation in the context of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta and in compliance with Rule 3520 of the Public Company Accounting Oversight Board.
Additional Information
Additional information in relation to TransAlta may be found under TransAlta's profile on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
Additional information including directors' and officers' remuneration and indebtedness, principal holders of our securities and securities authorized for issuance under equity compensation plans (all where applicable) is contained in our Management Proxy Circular for the most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from our Investor Relations department, or as filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
Additional financial information is provided in our audited consolidated financial statements as at and for the year ended Dec. 31, 2020, and in the related Annual MD&A, each of which is incorporated by reference in this AIF. See "Documents Incorporated by Reference."
Audit, Finance and Risk Committee
General
The members of TransAlta's Audit, Finance and Risk Committee ("AFRC") satisfy the requirements for independence under the provisions of Canadian Securities Regulators, National Instrument 52-110 Audit Committees, Section 303A of the NYSE Rules and Rule 10A-3 under the U.S. Securities and Exchange Act of 1934. The AFRC's Charter requires that it be made up of a minimum of three independent directors. The AFRC is currently comprised of four independent members: Beverlee F. Park (Chair), Alan J. Fohrer, Georgia R. Nelson and Bryan D. Pinney.
All members of the committee are financially literate pursuant to both Canadian and US securities requirements and Ms. Park and Mr. Pinney have each been determined by the Board to be an "audit committee financial expert," within the meaning of Section 407 of the United States Sarbanes Oxley Act of 2002 .
Mandate of the Audit, Finance and Risk Committee
The AFRC provides assistance to the Board in fulfilling its oversight responsibilities with respect to:
•the integrity of the Corporation's financial statements and financial reporting process,
•the systems of internal financial controls and disclosure controls established by management,
•the risk identification and assessment process conducted by management including the programs established by management to respond to such risks,
•the internal audit function,
•compliance with financial, legal and regulatory requirements and
•the external auditors' qualifications, independence and performance.
In so doing, it is the AFRC's responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and management of the Corporation.
The function of the AFRC is oversight. Management is responsible for the preparation, presentation and integrity of the interim and annual financial statements and related disclosure documents. Management of the Corporation is also responsible for maintaining appropriate accounting and financial reporting policies and systems of internal controls and
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disclosure controls and procedures to comply with accounting standards, applicable laws and regulations that provide reasonable assurance that the assets of the Corporation are safeguarded and transactions are authorized, executed, recorded and properly reported.
While the AFRC has the responsibilities and powers set forth herein, it is not the duty of the AFRC to plan or conduct audits or to determine that the Corporation's financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors.
The AFRC must also designate at least one member as an "audit committee financial expert." The designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which the individual will bring to bear in carrying out his or her duties on the AFRC. Designation as an "audit committee financial expert" does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on another member of the AFRC and Board in the absence of such designation.
Management is also responsible for the identification and management of the Corporation's risks and the development and implementation of policies and procedures to mitigate such risks. The AFRC's role is to provide oversight in order to ensure that the Corporation's assets are protected and safeguarded within reasonable business limits. The AFRC reports to the Board on its risk oversight responsibilities.
Audit, Finance and Risk Committee Charter
The Charter of the AFRC is attached as Appendix "A".
Relevant Education and Experience of Audit, Finance and Risk Committee Members
The following is a brief summary of the education or experience of each member of the AFRC that is relevant to the performance of his or her responsibilities as a member of the AFRC, including any education or experience that has provided the member with an understanding of the accounting principles that we use to prepare our annual and interim financial statements.

Name of AFRC Member | Relevant Education and Experience
Georgia R. Nelson | Mrs. Nelson holds a Master of Business Administration from the University of Southern California. She is the former Principal Officer and President of Midwest Generation and has more than 10 years of audit committee service on other public company boards.
Alan J. Fohrer | Prior to his retirement in December 2010, Mr. Fohrer was Chairman and CEO of SCE, a subsidiary of Edison and one of the largest electric utilities in the United States. Prior to that, Mr. Fohrer served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE. Mr. Fohrer also serves on the audit committee of PNM Resources Inc., a public company.
Beverlee . F. Park (Chair) | Ms. Park has executive experience in a range of industries, including forest products, shipping, mining, transportation, real estate, and electricity transmission. Ms. Park spent 17 years of her career with TimberWest Forest Corp. where she was most recently Chief Operations Officer. Over that time, she also held the roles of Interim Chief Executive Officer, President of the real estate division (Couverdon Real Estate) and Executive Vice President and Chief Financial Officer. Ms. Park is currently a director of SSR Mining Inc. where she chairs the Audit Committee. She was formerly a director of Teekay LNG Partners, InTransit BC and BC Transmission Corp. where she chaired the audit committees of all these boards. Ms. Park holds a Bachelor of Commerce with distinction from McGill University, a Master of Business Administration from the Simon Fraser University Executive program and is a Chartered Accountant. She is named a Fellow of the Chartered Professional Accountants of British Columbia in 2011.
Bryan D. Pinney | Mr. Pinney has more than 30 years of experience in financial auditing, valuation and advising companies in energy and natural resources. He has been an independent director of North American Construction Group Ltd. since 2015 and its lead director since Oct. 31, 2017. He is also a director of Sundial Growers Inc., a NASDAQ-listed company, where he also serves as Chair of the Audit & Risk Committee. He served as member of Deloitte’s Board of Directors and chair of the Finance and Audit Committee. He was the recent Chair of the Board of Governors and member of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He has been an independent non-executive director at Persta Resources Inc., a Hong Kong listed oil and gas exploration company. He has been a Chartered Accountant since December 1978, a Fellow of the Chartered Professional Accountants of Alberta since January 2009 and a Chartered Business Valuator of Canada since December 1990. Mr. Pinney obtained a Bachelor of Arts in business administration from the University of Western Ontario in 1975 and also completed the Directors Education Program offered by the Institute of Corporate Directors in Canada in 2012.

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Other Board Committees
In addition to the AFRC, TransAlta has three other standing committees: the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee. The members of these committees as at Dec. 31, 2020 are:

Governance, Safety and Sustainability Committee | Human Resources Committee
Chair: Rona H. Ambrose | Chair: Bryan D. Pinney
Sandra R. Sharman | Rona H. Ambrose
Yakout Mansour | Sandra R. Sharman
Alan J. Fohrer | Beverlee F. Park

Investment Performance Committee
Chair: Yakout Mansour
Georgia Nelson
Harry Goldgut
Richard Legault
Charters of the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee may be found on our website under Governance, Board Committees at www.transalta.com. Further information about the Board and our corporate governance may also be found on our website or in our Management Proxy Circular which is filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
For the years ended Dec. 31, 2020 and Dec. 31, 2019, Ernst & Young LLP and its affiliates billed $4,253,798 and $4,171,813, respectively, as detailed below:
Fees Paid to Ernst & Young LLP

Ernst & Young LLP
Year Ended December 31 | 2020 | 2019
Audit Fees(1) | $ | 2,273,888 |  | $ | 2,475,985 |
Audit-related fees(1)(2) |  | 1,122,771 |  |  | 1,356,412 |
Tax fees |  | 857,139 |  |  | 339,415 |
All other fees |  | — |  |  |  | — |  |
Total | $ | 4,253,798 |  | $ | 4,171,813 |

(1) Comparative figures have been reclassified to confirm to the current periods classification of fees.
(2) Included in the audit-related fees are $722,733 (2019 - $905,580) of fees billed to TransAlta Renewables.
No other audit firms provided audit services in 2020 or 2019.
The nature of each category of fees is described below:
Audit Fees
Audit fees are for professional services rendered for the audit and review of our financial statements or services provided in connection with statutory and regulatory filings and providing comfort letters associated with securities documents.
Audit-Related Fees
Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees". Audit-related fees include statutory audits, pension audits and other compliance audits. In 2020 and 2019, we have included the fees billed to TransAlta Renewables, a controlled and consolidated subsidiary of TransAlta.
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Tax Fees
Tax fees are tax-related services for review of tax returns, assistance with questions on tax audits, and tax planning.
All Other Fees
Products and services provided by the 'Corporation's auditor other than those services reported under "Audit Fees", "Audit-Related Fees" and "Tax Fees." This includes fees related to training services provided by the auditor.
Pre-Approval Policies and Procedures
The AFRC has considered whether the provision of services other than audit services is compatible with maintaining the auditors' independence. In May 2002, the AFRC adopted a policy that prohibits TransAlta from engaging the auditors for "prohibited" categories of non-audit services and requires pre-approval of the AFRC for other permissible categories of non-audit services, such categories being determined under the Sarbanes Oxley Act. This policy also provides that the Chair of the AFRC may approve permissible non-audit services during the quarter and report such approval to the AFRC at its next regularly scheduled meeting.
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Appendix "A"
TransAlta Corporation
(the “Corporation”)
Audit, Finance and Risk Committee Charter
A. Establishment of Committee and Procedures
1. Composition of Committee
The Audit, Finance and Risk Committee (the "Committee") of the Board of Directors (the "Board") of TransAlta Corporation (the "Corporation") shall consist of not less than three Directors. All members of the Committee shall be determined by the Board to be independent as required under the provisions of Canadian Securities Regulators' Multilateral Instrument 52-110 Audit Committees, Section 303A of the New York Stock Exchange rules and Rule 10A-3 of the U.S. Securities and Exchange Act of 1934, as such rules apply to audit committee members. All members of the Committee must be financially literate pursuant to both Canadian and U.S. securities requirements and at least one member must be determined by the Board to be an "audit committee financial expert" within the meaning of Section 407 of the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act"). Determinations as to whether a particular director satisfies the requirements for membership on the Committee shall be made by the Board at the recommendation of the Governance, Safety and Sustainability Committee (the "GSSC").
2. Appointment of Committee Members
Members of the Committee shall be appointed from time to time by the Board, on the recommendation of the GSSC, and shall hold office until the next annual meeting of shareholders, or until their successors are earlier appointed, or until they cease to be Directors of the Corporation.
3. Vacancies
Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board and on the recommendation of the GSSC. The Board shall fill any vacancy if the membership of the Committee is less than three directors.
4. Committee Chair
The Board shall appoint a Chair for the Committee on the recommendation of the GSSC.
5. Absence of Committee Chair
If the Chair of the Committee is not present at any meeting of the Committee, one of the members of the Committee who is present at the meeting shall be chosen by the Committee to preside at the meeting.
6. Secretary of Committee
The Committee shall appoint a Secretary who need not be a director of the Corporation.
7. Meetings
The Chair of the Committee may call a regular meeting of the Committee. The Committee shall meet at least quarterly and at such other time during each year as it deems appropriate to fulfil its responsibilities. In addition, the Chair of the Committee or any two members may call a special meeting of the Committee at any time.
The Committee shall also meet in separate executive session.
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8. Quorum
A majority of the members of the Committee, present in person or by telephone or other telecommunication device that permits all persons participating in the meeting to speak to each other shall constitute a quorum.
9. Notice of Meetings
Notice of the time and place of every meeting shall be given in writing (including by way of written facsimile communication or email) to each member of the Committee at least 48-hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive notice of a meeting; and attendance of a member at a meeting constitutes a waiver of notice of the meeting, except where a member attends for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called. Notice of every meeting shall also be provided to the external and internal auditors.
10. Attendance at Meetings
At the invitation of the Chair of the Committee, other Board members, the President and Chief Executive Officer ("CEO"), other officers or employees of the Corporation, the external auditors, and other experts or consultants may attend a meeting of the Committee.
11. Procedure, Records and Reporting
Subject to any statute or the articles and by-laws of the Corporation, the Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board generally not later than the next scheduled meeting of the Board.
12. Review of Charter and Evaluation of Committee
The Committee shall evaluate its performance and review and assess the adequacy of its Charter at least annually or otherwise, as it deems appropriate. All changes proposed by the Committee are reviewed and approved by the GSSC and the Board.
13. Outside Experts and Advisors
In consultation with the Board, the Committee Chair, on behalf of the Committee or any of its members, is authorized, at the expense of the Corporation, when deemed necessary or desirable, to retain independent counsel, outside experts and other advisors to advise the Committee independently on any matter. The retention of such counsel, expert or advisor in no way requires the Committee to act in accordance with the recommendations of such counsel, expert or advisor.
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B. Duties and Responsibilities of the Chair
The fundamental responsibility of the Chair of the Committee is to effectively manage the duties of the Committee.
The Chair is responsible for:
1. Chairing meetings of the Committee and ensuring that the Committee is properly organized so that it functions effectively and meets its obligations and responsibilities.
2. Establishing the frequency of Committee meetings, duly convening the same and confirming that quorum is present when required.
3. Working with the CEO, the Chief Financial Officer (the "CFO"), the Corporate Secretary and Assistant Corporate Secretary, as applicable, on the development of agendas and related materials for the meetings.
4. Providing leadership to the Committee and assisting the Committee in ensuring the proper and timely discharge of its responsibilities.
5. Reporting to the Board on the recommendations and decisions of the Committee.
The Chair of the Committee shall review all expense accounts and perquisites of the Chair of the Board and the CEO not less than quarterly to ensure compliance with the Corporation’s policies, and shall report to the Committee on an annual basis.
C. Mandate of the Committee
The Committee provides assistance to the Board in fulfilling its oversight responsibilities with respect to i) the integrity of the Corporation's financial statements and financial reporting process, ii) the systems of internal financial controls and disclosure controls established by Management, iii) the risk identification and assessment process conducted by Management including the programs established by Management to respond to such risks, iv) the internal audit function, v) compliance with financial, legal and regulatory requirements and vi) the external auditors' qualifications, independence and performance. In so doing, it is the Committee's responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and Management of the Corporation.
The function of the Committee is oversight. Management is responsible for the preparation, presentation and integrity of the interim and annual financial statements and related disclosure documents. Management of the Corporation is also responsible for maintaining appropriate accounting and financial reporting policies and systems of internal controls and disclosure controls and procedures to comply with accounting standards, applicable laws and regulations which provide reasonable assurance that the assets of the Corporation are safeguarded and transactions are authorized, executed, recorded and properly reported.
While the Committee has the responsibilities and powers set forth herein, it is not the duty of the Committee to plan or conduct audits or to determine that the Corporation's financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of Management and the external auditors.
The Committee must also designate at least one member as an "audit committee financial expert." The designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which the individual will bring to bear in carrying out his or her duties on the Committee. Designation as an "audit committee financial expert" does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on another member of the Committee and Board in the absence of such designation.
Management is also responsible for the identification and management of the Corporation's risks and the development and implementation of policies and procedures to mitigate such risks. The Committee's role is to provide oversight in order to ensure that the Corporation's assets are protected and safeguarded within reasonable business limits. The Committee reports to the Board on its risk oversight responsibilities.
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D. Duties and Responsibilities of the Committee
1. Financial Reporting, External Auditors and Financial Planning
A) Duties and Responsibilities Related to Financial Reporting and the Audit Process
(a) Review with Management and the external auditors the Corporation's financial reporting process the work to be conducted in conjunction with the annual audit and the preparation of the financial statements, including, without limitation, the annual audit plan of the external auditors, the judgment of the external auditors as to the quality, not just the acceptability, of and the appropriateness of the Corporation's accounting principles as applied in its financial reporting and the degree of aggressiveness or conservatism of the Corporation's accounting principles and underlying estimates;
(b) Review with Management and the external auditors the Corporation's audited annual financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and recommend their approval to the Board for release to the public;
(c) Review with Management and the external auditors the Corporation's interim financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and approve their release to the public as required;
(d) In reviewing the financial statements and related financial disclosure, the Committee shall review and discuss with Management and the external auditors:
(i) any changes in accounting principles, practices or policies considering their applicability to the business and financial impact;
(ii) Management's processes for formulating sensitive accounting estimates and the reasonableness of the estimates;
(iii) the use of "pro forma" or "non-comparable" information and the applicable reconciliation;
(iv) alternative treatments of financial information within generally accepted accounting principles that have been discussed between Management and the auditors, ramifications of the use of such alternative disclosures and treatments and the treatment preferred by the external auditors; and
(v) disclosures made to the Committee by the CEO and CFO during their certification process for the relevant periodic/annual report filed with securities regulators to ensure that information required to be disclosed is recorded, processed, summarized and reported within the time periods specified for the reporting period. Obtain assurances from the CEO and CFO as to the adequacy and effectiveness of the Corporation's disclosure controls and procedures and systems of internal control over financial reporting and that any fraud involving Management or other employees who have a significant role in the Corporation's internal controls is reported to the Committee.
(e) In reviewing the financial statements and related financial disclosure, the Committee shall also, with the external auditors:
(i) discuss the cooperation they received from Management during the course of their review and their access to all records, data and information requested; and
(ii) satisfy itself that there are no unresolved issues between Management and the external auditors that could reasonably be expected to materially affect the financial statements.
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(f) Review quarterly with senior Management, the Chief Legal and Compliance Officer (or, as necessary, outside legal advisors), and the Corporation's internal and external auditors, the effectiveness of the Corporation's internal controls to ensure the Corporation is in compliance with legal and regulatory requirements and the Corporation's policies;
(g) Review with Management and the external auditors the processes relating to the assessment of potential fraud, programs and controls to mitigate the risk of fraud, and the processes put in place for monitoring the risks within the targeted areas; and
(h) Discuss with Management and the external auditors any correspondence from or with regulators or governmental agencies, any employee complaints or any published reports that raise material issues regarding the Corporation's financial statements or accounting policies.
B) Duties and Responsibilities Related to the External Auditors
(a) The Committee shall have direct responsibility for the compensation and oversight of the external auditors including nominating the external auditors to the Board for appointment by the shareholders at the Corporation's general annual meeting. In performing its function, the Committee shall:
(i) review and approve annually the external auditors audit plan;
(ii) review and approve the basis and amount of the external auditors' fees and ensure the Corporation has provided appropriate funding for payment of compensation to the external auditors;
(iii) subject to the delegation granted to the Chair of the Committee, pre-approve all audit related services including all non-prohibited non-audit services provided by the external auditors; the Chair of the Committee is authorized to approve all audit related services including non-prohibited non-audit services provided by the external auditors, and shall report all such approvals to the Committee at its next scheduled meeting;
(iv) review and discuss annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors' independence, including, without limitation, (a) requesting, receiving and reviewing, at least annually, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on their independence with the Corporation; (b) discussing with the external auditors any relationships or services that the external auditors believe may affect their objectivity and professional skepticism; (c) reviewing with the external auditors the experience and qualifications of the senior personnel who are providing audit services to the Corporation; (d) reviewing the quality control procedures of the external auditors, including obtaining confirmation that the external auditors are in compliance with Canadian and U.S. regulatory registration requirements; and (e) evaluating the communication and interaction with the external auditor including quality of service considerations;
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(v) in the year preceding the change of the lead (or coordinating) audit partner (having primary responsibility for the audit), and in any event not less than every five years, perform a comprehensive review of the external auditor which takes into consideration (a) the impact of the tenure of the audit firm on audit quality, trends in the audit firm's performance and expertise in the industry, incidences of independence threats and the effectiveness of safeguards to mitigate those threats, (b) the responsiveness of the audit firm to changes in the entity's business and suggestions for improvement from regulators, the audit committee and/or management, (c) the consistency and rigour of the professional skepticism applied by the external auditor, and the quality of the engagement team and its communications, review of Canadian Public Accountability Board (CPAB) inspection findings since the previous comprehensive review and how the audit firm responded to these findings, and following this comprehensive review, determine whether the audit firm should be nominated to the Board as the external auditors for appointment by the shareholders at the Corporation's next general annual meeting;
(vi) inform the external auditors and Management that the external auditors shall have direct access to the Committee at all times, as well as the Committee to the external auditors;
(vii) instruct the external auditors that they are ultimately accountable to the Committee as representatives of the shareholders of the Corporation; and
(viii) at least annually, obtain and review the external auditors' report with respect to the auditing firm's internal quality-control procedures, any material issues raised by the most recent internal quality-control review or peer review of the auditing firm, any inquiry or investigation by governmental or professional authorities within the preceding five years undertaken respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues.
C) Duties and Responsibilities Related to Financial Planning
(a) Review and recommend to the Board for approval the Corporation's issuance and redemption of securities (including the review of all public filings to effect any of the issuances or redemptions), financial commitments and limits, and any material changes underlying any of these commitments;
(b) Review annually the Corporation's annual tax plan;
(c) Receive regular updates with respect to the Corporation's financial obligations, loans, credit facilities, credit position and financial liquidity;
(d) Review annually with Management the Corporation's overall financing plan in support of the Corporation's capital expenditure plan and overall budget/medium range forecast; and
(e) Review with Management at least annually the approach and nature of earnings guidance and financial information to be disclosed to analysts and rating agencies.
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2. Internal Audit
(a) Approve whether the internal audit function should be outsourced and if outsourced, approve the audit firm to perform such internal audit service; provided that in no event shall the external auditor be retained to also perform the internal audit function;
(b) Review and consider, as appropriate, any significant reports and recommendations made by internal audit relating to internal audit issues, together with Management's response thereto;
(c) Review annually the scope and plans for the work of the internal audit group, the adequacy of the group's resources, the internal auditors' access to the Corporation's records, property and personnel;
(d) Recognize and advise senior Management that the internal auditors shall have unfettered access to the Committee, as well as the Committee to the internal auditors;
(e) Meet separately with Management, the external auditors and internal auditors to review issues and matters of concern respecting audits and financial reporting;
(f) Review with the Corporation's senior financial Management and the internal audit group the adequacy of the Corporation's systems of internal control and procedures; and
(g) Recommend to the Human Resources Committee the appointment, termination or transfer of the lead individual responsible for internal audit, provided that if the internal audit function has been, or is being, outsourced to an audit firm, the Committee itself shall approve the appointment, termination or transfer of such audit firm.
3. Risk Management
The Board is responsible for ensuring that the Corporation has adopted processes and key policies for the identification, assessment and management of its principal risks. The Board has delegated to the Committee the responsibility for the oversight of Management's identification, and evaluation, of the Corporation's principal risks, and the implementation of appropriate policies, processes and systems to manage or mitigate the risks within the Corporation's risk appetite. The Committee reports to the Board thereon.
The Committee shall:
(a) Review, at least quarterly, Management's assessment of the Corporation's principal risks; discuss with Management the processes for the identification of these risks and the efficacy of the policies and procedures for mitigating and/or addressing these risks;
(b) Receive and review Managements' quarterly risk update including an update on residual risks;
(c) Review the Corporation's enterprise risk management framework and reporting methodology;
(d) Review annually the Corporation's Financial and Commodity Exposure Management Policies and approve changes to such policies;
(e) Review and approve the Corporation's strategic hedging program, guidelines and risk tolerance;
(f) Review and monitor quarterly results of financial and commodity exposure management activities, including foreign currency and interest rate risk strategies, counterparty credit exposure and the use of derivative instruments;
(g) Review the Corporation's annual insurance program, including the risk retention philosophy, potential exposure and corporate liability protection programs;
(h) Periodically consider the respective roles and responsibilities of the external auditor, the internal audit department, internal and external counsel concerning risk management and review their performance in relation to such roles and responsibilities; and
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(i) Annually, together with Management, report and review with the Board:
(i) the Corporation's principal risks and overall risk appetite/profile;
(ii) the Corporation's strategies in addressing its risk profile;
(iii) the processes, policies, procedures and controls in place to manage or mitigate the principal risks; and
(iv) the overall effectiveness of the enterprise risk management process and program.
4. Governance
A) Public Disclosure, Legal and Regulatory Reporting
(a) On behalf of the Committee, the Chair shall review all public disclosure inclusive of material financial information extracted or derived from the Corporation's financial statements prior to dissemination to the public;
(b) Review quarterly with the Chief Legal and Compliance Officer, and, if necessary, outside legal advisors, significant legal, compliance or regulatory matters that may have a material effect on the Corporation's financial statements;
(c) Discuss with the external auditors their perception of the Corporation's financial and accounting personnel, any recommendations which the external auditors may have, including those contained in the Management letter, with respect to improving internal financial controls, choice of accounting principles or management reporting systems, and review all Management letters from the external auditors together with Management's written responses thereto;
(d) Review with Management, the external auditors and internal legal counsel (external counsel if necessary), any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Corporation, and the manner in which these may be or have been disclosed in the financial statements;
(e) Review annually the Insider Trading Policy and approve changes as required; and
(f) Review annually the Corporation's Disclosure Policy and Social Media Policy to ensure continued applicability with the law and the Corporation's disclosure principles.
B) Pension Plan Governance
(a) Review annually the Annual Pension Report and financial statements of the Corporation's pension plans including the actuarial valuation, asset/liability forecast, asset allocation, manager performance and plan operating costs, and reporting thereon to the Board annually; and
(b) Together with the Human Resources Committee of the Board, review annually, and as required, the overall governance of the Corporation's Pension Plans, approving the broad objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually.
C) Information Technology – Cybersecurity
(a) Receive bi-annually a system status update with respect to the Corporation's core IT operating systems; and
(b) Review annually the Corporation's cybersecurity programs and their effectiveness. Receive an update on the Corporation's compliance program for cyber threats and security.
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D) Administrative Responsibilities
(a) Review the annual audit of expense accounts and perquisites of the Directors, the CEO and the CEO's direct reports and their use of corporate assets;
(b) Establish procedures for the receipt, retention and treatment of complaints relating to securities law, accounting, internal accounting controls, auditing or financial reporting matters, and potential ethical or legal violations;
(c) Review all incidents, complaints or information reported through the Ethics Help Line addressed to the Committee or relating to potential or suspected material breaches of securities laws, accounting, internal accounting controls, auditing or financial reporting matters and any material ethical or legal violation;
(d) Establish procedures for the investigation of complaints or allegations, and, in respect of potentially material complaints or allegations, report to the Board thereon and ensure that appropriate action is taken as necessary to address such matter;
(e) Review and consider any related party transaction and to recommend, if necessary, the use of a standing committee or an ad hoc special committee to assist the Board in the evaluation of any such related party transaction;
(f) Review and approve the Corporation's hiring policies for employees or former employees of the external auditors and monitor the Corporation's adherence to the policy; and
(g) Report annually to shareholders on the work of the Committee during the year.
E. Compliance and Powers of the Committee
(a) The responsibilities of the Committee comply with applicable Canadian laws and regulations, such as the rules of the Canadian Securities Administrators, and with the disclosure and listing requirements of the Toronto Stock Exchange, as they exist on the date hereof. In addition, this Charter complies with applicable U.S. laws, such as the Sarbanes-Oxley Act and the rules and regulations adopted thereunder, and with the New York Stock Exchange's corporate governance standards, as they exist on the date hereof.
(b) The Committee may, at the request of the Board or on its own initiative, investigate such other matters as are considered necessary or appropriate in carrying out its mandate.
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Appendix "B"
Glossary of Terms
This Annual Information Form includes the following defined terms:
"AESO" – Alberta Electric System Operator.
"Air e missions" – Substances released to the atmosphere through industrial operations. For the fossil-fuel-fired power sector, the most common air emissions are sulphur dioxide, oxides of nitrogen, mercury, and GHGs.
"Alberta PPA" – Alberta Power Purchase Arrangement – A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to PPA buyers.
"AUC" – Alberta Utilities Commission.
"Availability" – A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.
"Balancing Pool" – The Balancing Pool was established in 1999 by the Government of Alberta to help manage the transition to competition in Alberta's electric industry. Their current obligations and responsibilities are governed by the Electric Utilities Act (effective June 1, 2003) and the Balancing Pool Regulation. For more information, please go to www.balancing pool.ca
"Boiler" – A device for generating steam for power, processing or heating purposes, or for producing hot water for heating purposes or hot water supply. Heat from an external combustion source is transmitted to a fluid contained within the tubes of the boiler shell.
"Capacity" – The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.
"Cogeneration" – A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, heating, or cooling purposes.
"Combined-c ycle" – An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity. This process increases the efficiency of the electric generating unit.
"E 2 SG" – Economic, Environmental, Social and Governance
"Force m ajeure" – Literally means "greater force." These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.
"GGPPA" – Greenhouse Gas Pollution Pricing Act (Canada).
"GHG" – Greenhouse gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.
"Gigawatt" – A measure of electric power equal to 1,000 MW.
"GWh" – Gigawatt hour – A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.
"IESO" – Independent Electricity System Operator.
"LTC" – Long-term contract.
"MW" – Megawatt – A measure of electric power equal to 1,000,000 watts.
"MWh" – Megawatt hour – A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.
"Net capacity" – The maximum capacity or effective rating, modified for ambient limitations, that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.
"NOx" – Nitrogen oxide.
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"ppmvd" – Parts per million by volume, dry basis.
"OBPS" – Output- Based Pricing Standard.
"Off-Coal Agreement" – Off-Coal Agreement dated Nov. 24, 2016 between, among others, TransAlta and Her Majesty the Queen in Right of Alberta.
"PPA" – Purchase power agreement.
"Renewables PPA" – Long-term power purchase agreements with certain subsidiaries of TransAlta Renewables providing for the purchase by TransAlta, for a fixed price, of all of the power produced at such subsidiaries.
"TA Cogen" – TransAlta Cogeneration LP.
"CO2e/GWh" – Carbon dioxide equivalent per gigawatt hour.
"CO 2 e/MWH" – Carbon dioxide equivalent per megawatt hour
"TSX" – Toronto Stock Exchange.
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